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 June 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
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 (  )

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)	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 AUGUST 7, 2007
FirstEnergy Corp., $.10 par value	304,835,407
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	5,290,596

FirstEnergy Corp. is the sole holder of 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., 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.

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 typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “believe,” “estimate” and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, 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, legislative and regulatory changes (including revised environmental requirements), and the legal and regulatory changes resulting from the implementation of the EPACT (including, but not limited to, the repeal of the PUHCA), 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, 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 FirstEnergy’s 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 Rate Stabilization Plan) and the PPUC (including Penn’s default service plan filing), the resolution of the Petitions for Review filed with the Commonwealth Court of Pennsylvania with respect to the transition rate plan filing for Met-Ed and Penelec, the continuing availability and operation of generating units, the ability of generating units to continue to operate at, or near full capacity, the inability to accomplish or realize anticipated benefits from strategic goals (including employee workforce initiatives), the anticipated benefits from voluntary pension plan contributions, 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, any final adjustment in the purchase price per share under the accelerated share repurchase program announced March 2, 2007, the risks and other factors discussed from time to time in the registrants’ SEC filings, and other similar factors.  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	1-25
FirstEnergy Corp.
	Consolidated Statements of Income	26
	Consolidated Statements of Comprehensive Income	27
	Consolidated Balance Sheets	28
	Consolidated Statements of Cash Flows	29
	Report of Independent Registered Public Accounting Firm	30
	Management's Discussion and Analysis of Financial Condition and	31-71
	Results of Operations
Ohio Edison Company
	Consolidated Statements of Income and Comprehensive Income	72
	Consolidated Balance Sheets	73
	Consolidated Statements of Cash Flows	74
	Report of Independent Registered Public Accounting Firm	75
	Management's Discussion and Analysis of Financial Condition and	76-79
	Results of Operations
The Cleveland Electric Illuminating Company
	Consolidated Statements of Income and Comprehensive Income	80
	Consolidated Balance Sheets	81
	Consolidated Statements of Cash Flows	82
	Report of Independent Registered Public Accounting Firm	83
	Management's Discussion and Analysis of Financial Condition and	84-87
	Results of Operations
The Toledo 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 Discussion and Analysis of Financial Condition and	92-95
	Results of Operations
Jersey Central Power & Light Company
	Consolidated Statements of Income and Comprehensive Income	96
	Consolidated Balance Sheets	97
	Consolidated Statements of Cash Flows	98
	Report of Independent Registered Public Accounting Firm	99
	Management's Discussion and Analysis of Financial Condition and	100-103
	Results of Operations

i

TABLE OF CONTENTS (Cont'd)

		Pages
Metropolitan Edison Company
	Consolidated Statements of Income and Comprehensive Income	104
	Consolidated Balance Sheets	105
	Consolidated Statements of Cash Flows	106
	Report of Independent Registered Public Accounting Firm	107
	Management's Discussion and Analysis of Financial Condition and	108-111
	Results of Operations
Pennsylvania Electric 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 Discussion and Analysis of Financial Condition and	116-119
	Results of Operations
Combined Management’s Discussion and Analysis of Registrant Subsidiaries		120-132
Item 3.                      Quantitative and Qualitative Disclosures About Market Risk.		133
Item 4.                      Controls and Procedures.		133
Part II.    Other Information
Item 1.                      Legal Proceedings.		134
Item 1A.                      Risk Factors.		134
Item 2.                      Unregistered Sales of Equity Securities and Use of Proceeds.		134
Item 4.                      Submission of Matters to a Vote of Security Holders.		134-135
Item 6.                      Exhibits.		135-137

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
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
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
ECO	Electro-Catalytic Oxidation
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”
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 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”
Fitch	Fitch Ratings, Ltd.
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
NOAC	Northwest Ohio Aggregation Coalition
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
RTC	Regulatory Transition Charge
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 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
UCS	Union of Concerned Scientists
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

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 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 3). As discussed in Note 12, interim period segment reporting in 2006 was reclassified to conform with the current year business segment organizations and operations. 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 7) when it is determined to be the VIE's primary beneficiary. Investments in non-consolidated affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control (20-50% owned companies, joint ventures and partnerships) are accounted for under the equity method. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income. Certain prior year amounts have been reclassified to conform to the current year presentation.

The consolidated financial statements as of June 30, 2007 and for the three-month and six-month periods ended June 30, 2007 and 2006 have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their report (dated August 6, 2007) is included on page 28. 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 Act.

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 with an affiliate of Morgan Stanley and Co., Incorporated 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 approximately one year. The basic and diluted earnings per share calculations for the second quarter and first six months of 2007 reflect the impact associated with the March 2007 accelerated share repurchase program. 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					Six Months Ended
	June 30,					June 30,
Reconciliation of Basic and Diluted Earnings per Share	2007		2006			2007		2006
	(In millions, except per share amounts)
Income from continuing operations	$	338	$	312		$	628	$	531
Discontinued operations		-		(8	)		-		(6	)
Redemption premium on subsidiary preferred stock		-		(3	)		-		(3	)
Net earnings available for common shareholders	$	338	$	301		$	628	$	522
Average shares of common stock outstanding – Basic		304		328			309		328
Assumed exercise of dilutive stock options and awards		4		2			4		2
Average shares of common stock outstanding – Dilutive		308		330			313		330
Earnings per share:
Basic earnings per share:
Earnings from continuing operations	$	1.11	$	0.94		$	2.03	$	1.61
Discontinued operations		-		(0.02	)		-		(0.02	)
Net earnings per basic share	$	1.11	$	0.92		$	2.03	$	1.59
Diluted earnings per share:
Earnings from continuing operations	$	1.10	$	0.93		$	2.01	$	1.60
Discontinued operations		-		(0.02	)		-		(0.02	)
Net earnings per diluted share	$	1.10	$	0.91		$	2.01	$	1.58

3.  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 second quarter and six months ended June 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.

2

Revenues associated with discontinued operations were $34 million and $174 million in the second quarter and first six 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 six months ended June 30, 2006:

	Three Months				Six Months
	(In millions)
FSG subsidiaries	$	(8	)	$	(8	)
MYR		-			2
Total	$	(8	)	$	(6	)

4.  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.

The net deferred losses of $45 million included in AOCL as of June 30, 2007, for derivative hedging activity, as compared to $58 million as of December 31, 2006, resulted from a net $2 million decrease related to current hedging activity and an $11 million decrease due to net hedge losses reclassified into earnings during the six months ended June 30, 2007. Based on current estimates, approximately $17 million (after tax) of the net deferred losses on derivative instruments in AOCL as of June 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 six months of 2007, FirstEnergy unwound swaps with a total notional value of $150 million for which it incurred $8 million in cash losses, which will be recognized over the remaining maturity of each hedged security as interest expense. As of June 30, 2007, FirstEnergy had interest rate swaps with an aggregate notional value of $600 million and a fair value of $(30) million.

During 2006 and the first six 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 during 2007 and 2008 as outstanding debt matures. 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 six months of 2007, FirstEnergy terminated swaps with a notional value of $950 million for which it paid $2 million, all of which were deemed effective. FirstEnergy will recognize the loss over the life of the associated future debt. As of June 30, 2007, FirstEnergy had forward swaps with an aggregate notional amount of $250 million and a fair value of $6 million.

3

5.  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 June 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 June 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 six months ended June 30, 2007 and 2006, respectively.

Three Months Ended	FirstEnergy			OE		CEI			TE		JCP&L		Met-Ed		Penelec
	(In millions)
ARO Reconciliation
Balance, April 1, 2007	$	1,208		$	89	$	2		$	27	$	86	$	153	$	78
Liabilities incurred		-			-		-			-		-		-		-
Liabilities settled		-			-		-			-		-		-		-
Accretion		21			2		-			-		1		3		1
Revisions in estimated
cashflows		(1	)		-		-			-		-		-		-
Balance, June 30, 2007	$	1,228		$	91	$	2		$	27	$	87	$	156	$	79
Balance, April 1, 2006	$	1,148		$	84	$	8		$	25	$	81	$	144	$	73
Liabilities incurred		-			-		-			-		-		-		-
Liabilities settled		(6	)		-		(6	)		-		-		-		-
Accretion		18			1		-			1		1		2		1
Revisions in estimated
cashflows		-			-		-			-		-		-		-
Balance, June 30, 2006	$	1,160		$	85	$	2		$	26	$	82	$	146	$	74

Six Months Ended	FirstEnergy			OE		CEI			TE		JCP&L		Met-Ed		Penelec
	(In millions)
ARO Reconciliation
Balance, January 1, 2007	$	1,190		$	88	$	2		$	27	$	84	$	151	$	77
Liabilities incurred		-			-		-			-		-		-		-
Liabilities settled		-			-		-			-		-		-		-
Accretion		39			3		-			-		3		5		2
Revisions in estimated
cashflows		(1	)		-		-			-		-		-		-
Balance, June 30, 2007	$	1,228		$	91	$	2		$	27	$	87	$	156	$	79
Balance, January 1, 2006	$	1,126		$	83	$	8		$	25	$	80	$	142	$	72
Liabilities incurred		-			-		-			-		-		-		-
Liabilities settled		(6	)		-		(6	)		-		-		-		-
Accretion		36			2		-			1		2		4		2
Revisions in estimated
cashflows		4			-		-			-		-		-		-
Balance, June 30, 2006	$	1,160		$	85	$	2		$	26	$	82	$	146	$	74

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6.  PENSION AND OTHER POSTRETIREMENT BENEFITS

FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its 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 six months ended June 30, 2007 and 2006 consisted of the following:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Pension Benefits	2007			2006			2007			2006
	(In millions)
Service cost	$	21		$	21		$	42		$	41
Interest cost		71			66			142			133
Expected return on plan assets		(113	)		(99	)		(225	)		(198	)
Amortization of prior service cost		3			2			5			5
Recognized net actuarial loss		11			15			21			29
Net periodic cost (credit)	$	(7	)	$	5		$	(15	)	$	10

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Other Postretirement Benefits	2007			2006			2007			2006
	(In millions)
Service cost	$	5		$	9		$	10		$	17
Interest cost		17			26			34			52
Expected return on plan assets		(12	)		(12	)		(25	)		(23	)
Amortization of prior service cost		(37	)		(19	)		(74	)		(37	)
Recognized net actuarial loss		11			14			23			27
Net periodic cost (credit)	$	(16	)	$	18		$	(32	)	$	36

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Pension Benefit Cost (Credit)	2007			2006			2007			2006
	(In millions)
OE	$	(3.9	)	$	(1.5	)	$	(7.9	)	$	(2.9	)
CEI		0.3			1.0			0.6			1.9
TE		(0.1	)		0.2			(0.1	)		0.4
JCP&L		(2.2	)		(1.4	)		(4.3	)		(2.7	)
Met-Ed		(1.7	)		(1.7	)		(3.4	)		(3.5	)
Penelec		(2.5	)		(1.3	)		(5.1	)		(2.7	)
Other FirstEnergy subsidiaries		2.6			9.9			5.1			20.0
	$	(7.5	)	$	5.2		$	(15.1	)	$	10.5

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	Three Months Ended					Six Months Ended
	June 30,					June 30,
Other Postretirement Benefit Cost (Credit)	2007			2006		2007			2006
	(In millions)
OE	$	(2.6	)	$	4.2	$	(5.3	)	$	8.4
CEI		0.9			2.8		1.9			5.5
TE		1.2			2.0		2.4			4.0
JCP&L		(4.0	)		0.6		(8.0	)		1.2
Met-Ed		(2.6	)		0.7		(5.1	)		1.5
Penelec		(3.1	)		1.8		(6.3	)		3.6
Other FirstEnergy subsidiaries		(5.7	)		6.1		(11.4	)		12.1
	$	(15.9	)	$	18.2	$	(31.8	)	$	36.3

7.  VARIABLE INTEREST ENTITIES

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

Leases

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 $851 million, $790 million and $790 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 $619 million, $82 million and $442 million, respectively, that would not be payable if the casualty value payments are made.

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.

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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 June 30, 2007, the net above-market loss liability projected for these eight NUG agreements was $145 million. Purchased power costs from these entities during the three months and six months ended June 30, 2007 and 2006 are shown in the following table:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2007		2006		2007		2006
	(In millions)
JCP&L	$	21	$	19	$	41	$	34
Met-Ed		12		16		27		33
Penelec		7		7		15		14
Total	$	40	$	42	$	83	$	81

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 June 30, 2007, $411 million of the transition bonds are 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 that is payable from TBC collections.

8.  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 affect the effective tax rate would be purchase accounting adjustments to goodwill upon recognition. During the first six months of 2007, there were no material changes to FirstEnergy’s unrecognized tax benefits. As of June 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 12 months are not material.

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FIN 48 also requires companies to recognize interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes, consistent with its policy prior to implementing FIN 48. As of January 1, 2007, the net amount of interest accrued was $34 million. During the first six 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.

In the first six months of 2007, OE’s income taxes included an immaterial adjustment applicable to prior periods of $7.2 million related to an inter-company federal tax allocation arrangement among FirstEnergy and its subsidiaries.

9.  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 June 30, 2007, outstanding guarantees and other assurances aggregated approximately $4.1 billion, consisting of contract guarantees - $2.3 billion, surety bonds - $0.1 billion and LOCs - $1.7 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 $0.8 billion (included in the $2.3 billion discussed above) as of June 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.

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 June 30, 2007, FirstEnergy's maximum exposure under these collateral provisions was $421 million.

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $95 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

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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 June 30, 2007), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Plant 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. The transaction will be classified as a financing under GAAP until FGCO’s and 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 are satisfied, at which time it is expected to be classified as an operating lease under GAAP. This transaction generated tax capital gains of approximately $830 million, a substantial portion of which will be offset by existing tax capital loss carryforwards.  FirstEnergy expects to reduce its tax loss carryforward valuation allowances in the third quarter of 2007 and anticipates an immaterial impact to net income as the majority of the unrecognized tax benefits will reduce goodwill.

(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.

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 July 25, 2007, FirstEnergy and PennFuture entered into a Tolling and Confidentiality Agreement that provides for a 60-day negotiation period during which the parties have agreed to not file a lawsuit.

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-fired generation facilities will be subject to caps on SO₂ and NO_X emissions, whereas its New Jersey fossil-fired 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.

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.

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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.

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.

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On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system, and entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. On January 26, 2007, the 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 June 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, 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 June 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 $88 million (JCP&L - $60 million, TE - $3 million, CEI - $1 million, and other subsidiaries - $24 million) have been accrued through June 30, 2007.

(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.

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In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision on July 8, 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, on March 7, 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 on May 9, 2007.  Proceedings are continuing in the Superior Court.  FirstEnergy is vigorously defending this class action but is unable to predict the outcome of this matter.  No liability has been accrued as of June 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., 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 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.

On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga County Common Pleas Court seeking reimbursement for claims paid to numerous insureds who allegedly suffered losses as a result of the August 14, 2003 outages. All of the insureds appear to be non-customers. The plaintiff insurance companies are the same claimants in one of the pending PUCO cases. FirstEnergy, the Ohio Companies and Penn were served on October 27, 2006.  On January 18, 2007, the Court granted the Companies’ motion to dismiss the case and they have not been appealed.  However, on April 25, 2007, one of the insurance carriers refiled the complaint naming only FirstEnergy as the defendant.  On July 30, 2007, the case was voluntarily dismissed.  No estimate of potential liability is available for any of these cases.

FirstEnergy was also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy were based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. None of FirstEnergy’s subsidiaries serve customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss. The plaintiff has not appealed.

FirstEnergy is vigorously 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 August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee's failure to take prompt and corrective action. On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Nuclear Power Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections would continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.

On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance at the Perry Nuclear Power Plant and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. By two letters dated March 2, 2007, the NRC closed the CAL commitments for Perry, the two outstanding white findings, and crosscutting issues.  Moreover, the NRC removed Perry from the Multiple Degraded Cornerstone Column of the NRC Action Matrix and placed the plant in the Licensee Response Column (regular agency oversight).

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On April 30, 2007, the UCS filed a petition with the NRC under Section 2.206 of the NRC’s regulations based on a report prepared at FENOC’s request by expert witnesses for an insurance arbitration.  In December 2006, the expert witnesses for FENOC completed a report that analyzed the crack growth rates in control rod drive mechanism penetrations and wastage of the former reactor pressure vessel head at Davis-Besse.   Citing the findings in the expert witness' report, the Section 2.206 petition requested that: (1) Davis-Besse be immediately shut down; (2) that the NRC conduct an independent review of the consultant's report and that all pressurized water reactors be shut down until remedial actions can be implemented; and (3) Davis-Besse’s operating license be revoked.

In a letter dated May 18, 2007, the NRC stated that the “current reactor pressure vessel (RPV) head inspection requirements are adequate to detect RPV degradation issues before they result in significant corrosion.” The NRC also indicated that, “no immediate safety concern exists at Davis-Besse” and denied UCS’ first demand (to shut down the facility).  On June 18, 2007, the NRC Petition Review Board indicated that the agency had initially denied petitioner’s other requests, and provided an opportunity for UCS to provide additional information prior to the final determination. By letter dated July 12, 2007, the NRC denied the remainder of the UCS petition.

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 the expert witnesses’ report and another report. The NRC indicated that this information is 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. FirstEnergy can provide no assurances as to the ultimate resolution of this matter.

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 plaintiff’s motion to amend their complaint which OE has opposed.

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. 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. The parties met on June 27, 2007 before an arbitrator to assert their positions regarding the finality of damages. A hearing before the arbitrator is set for September 7, 2007.

The union employees at the W. H. Sammis Plant have been working without a labor contract since July 1, 2007. The union expects to vote on a new contract on August 9, 2007. While it is expected the union will ratify a new contract, FirstEnergy has a strike mitigation plan ready in the event of a strike.

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

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10.  REGULATORY MATTERS

(A)   RELIABILITY INITIATIVES

In late 2003 and early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. – Canada Power System Outage Task Force) regarding enhancements to regional reliability. 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 partly to amend the Federal Power Act with Section 215, which requires that an ERO establish and enforce reliability standards for the bulk-power system, subject to review of 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.

While the FERC approved 83 of the 107 reliability standards proposed by NERC, the FERC has directed NERC to submit improvements to 56 of them, endorsing NERC's process for developing reliability standards and its associated work plan. On May 4, 2007, NERC also submitted 24 proposed Violation Risk Factors.  The FERC issued an order approving 22 of those factors on June 26, 2007. Further, NERC adopted eight cyber security standards that became effective on June 1, 2006 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 assessment by February 12, 2007. The standards remain pending before the FERC.  On July 20, 2007, the FERC issued a NOPR proposing to adopt eight Critical Infrastructure Protection Reliability Standards.  Comments will not be due to the FERC until September or October of 2007.

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 will eventually adopt stricter NERC reliability 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.

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(B)   OHIO

On October 21, 2003, the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to the PUCO’s concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming the PUCO's order in all respects, except it remanded back to the PUCO the matter of ensuring the availability of sufficient means for customer participation in the marketplace. The RSP contained a provision that permitted the Ohio Companies to withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies have 30 days from the final order or decision to provide notice of termination. On July 20, 2006, the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding on Remand. In their Request, the Ohio Companies provided notice of termination to those provisions of the RSP subject to termination, subject to being withdrawn, and also set forth a framework for addressing the Supreme Court of Ohio’s findings on customer participation. If the PUCO approves a resolution to the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and considered to be null and void. On July 20, 2006, the OCC and NOAC also submitted to the PUCO a conceptual proposal addressing the issue raised by the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry directing the Ohio Companies to file a plan in a new docket to address the Court’s concern. The Ohio Companies filed their RSP Remand CBP on September 29, 2006. Initial comments were filed on January 12, 2007 and reply comments were filed on January 29, 2007. In their reply comments the Ohio Companies described the highlights of a new tariff offering they would be willing to make available to customers that would allow customers to purchase renewable energy certificates associated with a renewable generation source, subject to PUCO approval. On May 29, 2007, the Ohio Companies, together with the PUCO Staff and the OCC, filed a stipulation with the PUCO agreeing to offer a standard bid product and a green resource tariff product. The stipulation is currently pending before the PUCO. No further proceedings are scheduled at this time.

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 provided an update 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 late 2007. The PUCO order is expected to be issued by March 9, 2008. The new rates, subject to evidentiary hearings and approval at the PUCO, 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 Ohio Companies requested that the PUCO issue an order by November 1, 2007, to provide sufficient time to conduct the bidding process. The PUCO has scheduled a technical conference for August 16, 2007.

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(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 costs during the term of these agreements with FES.

On April 7, 2006, the parties entered into a tolling agreement that arose from FES’ notice to Met-Ed and Penelec that FES elected to exercise its right to terminate the partial requirements agreement effective midnight December 31, 2006. On November 29, 2006, Met-Ed, Penelec and FES agreed to suspend the April 7 tolling agreement pending resolution of the PPUC’s proceedings regarding the Met-Ed and Penelec comprehensive transition rate cases filed April 10, 2006, described below. Separately, 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 substantially exceed 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 tolling, suspension and 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.

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 in accordance with the April 7, 2006 tolling agreement described above. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs, but only for those 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 the merger savings, with the comprehensive transmission rate filing case.

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The PPUC entered its Opinion and Order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, 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 by all parties. Responsive briefs are due August 20, 2007, with reply briefs due September 4, 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 June 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 $493 million and $127 million, respectively. $82 million of Penelec’s deferral is subject to final resolution of an IRS settlement associated with NUG trust fund proceeds. 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 late 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. The PPUC is requested to act on the proposal no later than November 2007 for the initial RFP to take place in January 2008.

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On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation 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 will be 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 June 30, 2007, the accumulated deferred cost balance totaled approximately $392 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 Energy Master Plan (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;

·       Unit prices for electricity should remain 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 August 1, 2007, the NJBPU approved publication of a formal proposal in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following a period for public comment.  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 third 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 and Electric Company 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 American Electric Power Company, Inc., 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.

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 maintain existing transmission rates between MISO and PJM.  If accepted 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 transmission facilities across the entire MISO footprint be maintained.  All of these filings were supported by the majority of transmission owners in either MISO or PJM.

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 transmission facilities be spread throughout the entire MISO footprint.  If adopted by the FERC, this proposal would shift a greater portion of the cost of new 345 kV transmission facilities to the FirstEnergy footprint, and increase the transmission rates paid by load-serving FirstEnergy affiliates.

American Electric Power (AEP) filed a letter with the FERC Commissioners stating its intent to file a complaint under Section 206 of the Federal Power Act challenging the justness and reasonableness of the rate designs underlying the MISO and PJM transmission tariffs.  AEP will propose the adoption of a regional rate design that is expected to reallocate the cost of both existing and new high voltage transmission facilities across the combined MISO and PJM footprint.  Based upon the position advocated by AEP in a related proceeding, the AEP proposal is expected to result in a greater allocation of costs to FirstEnergy transmission zones in MISO and PJM.  If approved by the FERC, AEP’s proposal would increase the transmission rates paid by load-serving FirstEnergy affiliates.

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.

On February 15, 2007, MISO filed documents with the FERC to establish a market-based, competitive ancillary services market.  MISO contends that the filing will integrate operating reserves into MISO’s existing day-ahead and real-time settlements process, incorporate opportunity costs into these markets, address scarcity pricing through the implementation of a demand curve methodology, foster demand response in the provision of operating reserves, and provide for various efficiencies and optimization with regard to generation dispatch.  The filing also proposes amendments to existing documents to provide for the transfer of balancing functions from existing local balancing authorities to MISO.  MISO will then carry out this reliability function as the NERC-certified balancing authority for the MISO region with implementation in the third or fourth quarter of 2008.  FirstEnergy filed comments on March 23, 2007, supporting the ancillary service market in concept, but proposing certain changes in MISO’s proposal. MISO requested FERC action on its filing by June 2007 and the FERC issued its Order June 22, 2007. The FERC found MISO’s filing to be deficient in two key areas: (1) MISO has not submitted a market power analysis in support of its proposed Ancillary Services Market and (2) MISO has not submitted a readiness plan to ensure reliability during the transition from the current reserve and regulation system managed by the individual Balancing Authorities to a centralized Ancillary Services Market managed by MISO. MISO was ordered to remedy these deficiencies and the FERC provided more guidance on other issues brought up in filings by stakeholders to assist MISO to re-file a complete proposal. This Order should facilitate MISO’s timetable to incorporate final revisions to ensure a market start in Spring 2008. FirstEnergy will be participating in working groups and task forces to ensure the Spring 2008 implementation of the Ancillary Services Market.

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On February 16, 2007, the FERC issued a final rule 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. As a market participant in both MISO and PJM, FirstEnergy will conform its business practices to each respective revised tariff.

11.  NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

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.

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.

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 effect on FirstEnergy’s financial statements.

12.  SEGMENT INFORMATION

Effective January 1, 2007, FirstEnergy has three reportable operating segments: competitive energy services, energy delivery services and Ohio transitional generation services. None of the aggregate “Other” segments individually meet the criteria to be considered a reportable segment. 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 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 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.”

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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, provides competitive electric sales primarily in Ohio, Pennsylvania, Maryland and Michigan and owns 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.

The Ohio transitional generation services segment represents the regulated generation commodity operations of FirstEnergy’s Ohio electric utility subsidiaries. Its revenues are primarily derived from electric generation sales to non-shopping customers under the PLR obligations of the Ohio Companies. Its results reflect securing electric generation from the competitive energy services segment through full requirements PSA arrangements and the net MISO transmission revenues and expenses related to the delivery of that generation load.

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 Items."

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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)
June 30, 2007
External revenues	$	2,095	$	404	$	625		$	9		$	(24	)	$	3,109
Internal revenues		-		691		-			-			(691	)		-
Total revenues		2,095		1,095		625			9			(715	)		3,109
Depreciation and amortization		249		51		(49	)		1			5			257
Investment income		62		5		-			-			(37	)		30
Net interest charges		116		42		-			1			39			198
Income taxes		141		96		19			(3	)		(31	)		222
Net income		207		142		30			6			(47	)		338
Total assets		23,602		7,284		260			236			651			32,033
Total goodwill		5,873		24		-			1			-			5,898
Property additions		245		139		-			2			15			401
June 30, 2006
External revenues	$	1,773	$	384	$	575		$	39		$	(20	)	$	2,751
Internal revenues		6		623		-			-			(629	)		-
Total revenues		1,779		1,007		575			39			(649	)		2,751
Depreciation and amortization		173		48		(29	)		1			6			199
Investment income		81		2		-			-			(52	)		31
Net interest charges		102		47		-			2			22			173
Income taxes		155		67		22			2			(30	)		216
Income from
continuing operations		233		101		31			(7	)		(46	)		312
Discontinued operations		-		-		-			(8	)		-			(8	)
Net income		233		101		31			(15	)		(46	)		304
Total assets		24,399		6,740		231			355			853			32,578
Total goodwill		5,916		24		-			-			-			5,940
Property additions		177		103		-			-			12			292
Six Months Ended
June 30, 2007
External revenues	$	4,135	$	732	$	1,245		$	20		$	(50	)	$	6,082
Internal revenues		-		1,404		-			-			(1,404	)		-
Total revenues		4,135		2,136		1,245			20			(1,454	)		6,082
Depreciation and amortization		469		102		(64	)		2			11			520
Investment income		132		8		1			-			(78	)		63
Net interest charges		223		92		1			2			60			378
Income taxes		289		160		35			2			(64	)		422
Net income		425		240		53			7			(97	)		628
Total assets		23,602		7,284		260			236			651			32,033
Total goodwill		5,873		24		-			1			-			5,898
Property additions		400		263		-			3			31			697
June 30, 2006
External revenues	$	3,570	$	738	$	1,118		$	68		$	(38	)	$	5,456
Internal revenues		14		1,235		-			-			(1,249	)		-
Total revenues		3,584		1,973		1,118			68			(1,287	)		5,456
Depreciation and amortization		430		94		(49	)		2			11			488
Investment income		164		17		-			1			(108	)		74
Net interest charges		201		90		1			3			38			333
Income taxes		281		89		40			(3	)		(55	)		352
Income from
continuing operations		422		133		61			5			(90	)		531
Discontinued operations		-		-		-			(6	)		-			(6	)
Net income		422		133		61			(1	)		(90	)		525
Total assets		24,399		6,740		231			355			853			32,578
Total goodwill		5,916		24		-			-			-			5,940
Property additions		370		347		-			-			22			739

 

Reconciling adjustments to segment operating results from internal management reporting to consolidated external

financial reporting primarily consist of interest expense related to holding company debt, corporate support services

revenues and expenses and elimination of intersegment transactions.

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FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
	(In millions, except per share amounts)
REVENUES:
Electric utilities	$	2,744		$	2,341		$	5,425		$	4,681
Unregulated businesses		365			410			657			775
Total revenues *		3,109			2,751			6,082			5,456
EXPENSES:
Fuel and purchased power		1,185			991			2,306			1,989
Other operating expenses		750			718			1,499			1,471
Provision for depreciation		159			144			315			292
Amortization of regulatory assets		246			201			497			422
Deferral of new regulatory assets		(148	)		(146	)		(292	)		(226	)
General taxes		189			173			392			366
Total expenses		2,381			2,081			4,717			4,314
OPERATING INCOME		728			670			1,365			1,142
OTHER INCOME (EXPENSE):
Investment income		30			31			63			74
Interest expense		(205	)		(178	)		(390	)		(343	)
Capitalized interest		7			7			12			14
Subsidiaries’ preferred stock dividends		-			(2	)		-			(4	)
Total other expense		(168	)		(142	)		(315	)		(259	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		560			528			1,050			883
INCOME TAXES		222			216			422			352
INCOME FROM CONTINUING OPERATIONS		338			312			628			531
Discontinued operations (net of income tax expense (benefits) of
$1 million and ($1) million in the three months and
six months ended June 30, 2006, respectively) (Note 3)		-			(8	)		-			(6	)
NET INCOME	$	338		$	304		$	628		$	525
BASIC EARNINGS PER SHARE OF COMMON STOCK:
Income from continuing operations	$	1.11		$	0.94		$	2.03		$	1.61
Discontinued operations		-			(0.02	)		-			(0.02	)
Net earnings per basic share	$	1.11		$	0.92		$	2.03		$	1.59
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING		304			328			309			328
DILUTED EARNINGS PER SHARE OF COMMON STOCK:
Income from continuing operations	$	1.10		$	0.93		$	2.01		$	1.60
Discontinued operations		-			(0.02	)		-			(0.02	)
Net earnings per diluted share	$	1.10		$	0.91		$	2.01		$	1.58
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING		308			330			313			330
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	0.50		$	0.45		$	1.00		$	0.90
* Includes excise tax collections of $102 million and $90 million in the second quarter of 2007 and 2006, respectively, and $206 million
and $189 million in the six months ended June 2007 and 2006, respectively.
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.

26

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
	(In millions)
NET INCOME	$	338		$	304		$	628		$	525
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(11	)		-			(22	)		-
Unrealized gain (loss) on derivative hedges		(1	)		36			20			73
Change in unrealized gain on available for sale securities		46			(24	)		63			13
Other comprehensive income		34			12			61			86
Income tax expense related to other
comprehensive income		10			4			19			31
Other comprehensive income, net of tax		24			8			42			55
COMPREHENSIVE INCOME	$	362		$	312		$	670		$	580
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
these statements.

27

FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,			December 31,
	2007			2006
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	37		$	90
Receivables-
Customers (less accumulated provisions of $39 million and
$43 million, respectively, for uncollectible accounts)		1,413			1,135
Other (less accumulated provisions of $22 million and
$24 million, respectively, for uncollectible accounts)		181			132
Materials and supplies, at average cost		583			577
Prepayments and other		322			149
		2,536			2,083
PROPERTY, PLANT AND EQUIPMENT:
In service		24,555			24,105
Less - Accumulated provision for depreciation		10,330			10,055
		14,225			14,050
Construction work in progress		785			617
		15,010			14,667
INVESTMENTS:
Nuclear plant decommissioning trusts		2,092			1,977
Investments in lease obligation bonds		738			811
Other		734			746
		3,564			3,534
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		5,898			5,898
Regulatory assets		4,155			4,441
Pension assets		297			-
Other		573			573
		10,923			10,912
	$	32,033		$	31,196
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	2,000		$	1,867
Short-term borrowings		2,416			1,108
Accounts payable		801			726
Accrued taxes		320			598
Other		745			956
		6,282			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		5,550			6,466
Accumulated other comprehensive loss		(217	)		(259	)
Retained earnings		3,279			2,806
Unallocated employee stock ownership plan common stock-
134,681 and 521,818 shares, respectively		(2	)		(10	)
Total common stockholders' equity		8,640			9,035
Long-term debt and other long-term obligations		8,742			8,535
		17,382			17,570
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		2,849			2,740
Asset retirement obligations		1,228			1,190
Power purchase contract loss liability		877			1,182
Retirement benefits		917			944
Lease market valuation liability		704			767
Other		1,794			1,548
		8,369			8,371
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
	$	32,033		$	31,196
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these
balance sheets.

28

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30,
	2007			2006
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	628		$	525
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		315			292
Amortization of regulatory assets		497			421
Deferral of new regulatory assets		(292	)		(226	)
Nuclear fuel and lease amortization		50			42
Deferred purchased power and other costs		(185	)		(239	)
Deferred income taxes and investment tax credits, net		85			32
Investment impairment		12			12
Deferred rents and lease market valuation liability		(92	)		(105	)
Accrued compensation and retirement benefits		(69	)		33
Commodity derivative transactions, net		4			25
Gain on asset sales		(12	)		(4	)
Income from discontinued operations		-			6
Cash collateral		(19	)		(55	)
Pension trust contribution		(300	)		-
Decrease (increase) in operating assets-
Receivables		(282	)		83
Materials and supplies		22			(71	)
Prepayments and other current assets		(157	)		(159	)
Increase (decrease) in operating liabilities-
Accounts payable		28			(40	)
Accrued taxes		(17	)		(45	)
Electric service prepayment programs		(36	)		(29	)
Other		(49	)		(13	)
Net cash provided from operating activities		131			485
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		800			1,053
Short-term borrowings, net		1,308			371
Redemptions and Repayments-
Common stock		(918	)		-
Preferred stock		-			(30	)
Long-term debt		(471	)		(485	)
Net controlled disbursement activity		32			5
Stock-based compensation tax benefit		14			-
Common stock dividend payments		(311	)		(296	)
Net cash provided from financing activities		454			618
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(697	)		(739	)
Proceeds from asset sales		12			63
Sales of investment securities held in trusts		583			959
Purchases of investment securities held in trusts		(591	)		(966	)
Cash investments		54			118
Other		1			(19	)
Net cash used for investing activities		(638	)		(584	)
Net increase (decrease) in cash and cash equivalents		(53	)		519
Cash and cash equivalents at beginning of period		90			64
Cash and cash equivalents at end of period	$	37		$	583
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
these statements.

 

29

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 June 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2007 and 2006 and the consolidated statement of cash flows for the six-month periods ended June 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, 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

August 6, 2007

30

FIRSTENERGY CORP.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EXECUTIVE SUMMARY

Net income in the second quarter of 2007 was $338 million, or basic earnings of $1.11 per share of common stock ($1.10 diluted), compared with net income of $304 million, or basic earnings of $0.92 per share of common stock ($0.91 diluted) in the second quarter of 2006. Net income in the first six months of 2007 was $628 million, or basic earnings of $2.03 per share of common stock ($2.01 diluted), compared with net income of $525 million, or basic earnings of $1.59 per share of common stock ($1.58 diluted) in the first six months of 2006. The increases in FirstEnergy’s earnings in both periods of 2007 were driven primarily by higher electric sales revenues, partially offset by increased fuel and purchased power costs, higher other operating expenses and increased interest expense.

Change in Basic Earnings Per Share From Prior Year Periods	Three Months Ended June 30,			Six Months Ended June 30,
Basic Earnings Per Share – 2006	$	0.92		$	1.59
Revenues		0.71			1.22
Fuel and purchased power		(0.38	)		(0.62	)
Depreciation and amortization		(0.12	)		(0.19	)
Deferral of new regulatory assets		-			0.08
Other expenses		(0.03	)		(0.10	)
Non-core asset sales/impairments - 2006		0.03			0.03
Saxton decommissioning regulatory asset -2007		-			0.05
Trust securities impairment - 2007		(0.02	)		(0.03	)
Basic Earnings Per Share – 2007	$	1.11		$	2.03

Financial Matters

On July 13, 2007, FGCO completed a $1.3 billion sale and leaseback transaction for its 779 MW portion of the Bruce Mansfield Plant Unit 1. The terms of the agreement provide for an approximate 33-year lease of the unit. There will be no material gain from this transaction reflected in earnings during the third quarter of 2007. 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.  FGCO will continue to operate the plant.

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

Regulatory Matters

Ohio

On June 7, 2007, the Ohio Companies filed their base distribution rate increase request and supporting testimony with the PUCO.  The requested increase (updated on August 6, 2007) in annualized distribution revenues of approximately $332 million is needed to recover expenses related to distribution operations and the costs deferred under previously approved rate plans. Concurrent with the effective dates of the proposed distribution rate increases, the Ohio Companies will reduce or eliminate their RTC, resulting in a net reduction of $262 million on the regulated portion of customers’ bills. The PUCO Staff is expected to issue its report in the case in the fourth quarter of 2007 with evidentiary hearings to follow in late 2007.  The PUCO order is expected to be issued by March 9, 2008. The new rates would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.

31

On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing generation service to customers who do not purchase electricity from an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per kilowatt-hour included in rates would reflect an average of the prices resulting from all 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 also 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 Ohio Companies requested that the PUCO issue an order by November 1, 2007, to provide sufficient time to conduct the bidding process.

Pennsylvania

On May 2, 2007, Penn made a filing with the PPUC proposing how it will procure the power supply needed for default service customers from June 1, 2008 through May 2011. Hearings are scheduled for September 10-11, 2007, with a recommended ALJ decision expected by October 25, 2007.  A PPUC order is expected by November 29, 2007. The initial RFP is expected to take place in January 2008.

On May 3, 2007, an ALJ issued her initial decision denying 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 June 19, 2007, initial briefs were filed with the Commonwealth Court of Pennsylvania by all parties in the appeal of Met-Ed’s and Penelec’s comprehensive rate filing.  Responsive briefs are due August 20, 2007, with reply briefs due September 4, 2007.  Met-Ed and Penelec appealed the PPUC’s decision on the denial of generation rate relief and consolidated tax savings, while other parties appealed the PPUC’s decision on transmission rate relief.  Oral arguments are expected to take place in the fourth quarter of 2007.

Operations

Second Quarter KWH Sales Record - FirstEnergy set a new second quarter generation sales record in 2007 of 32.8 billion KWH, which represents a 2.9% increase over the second quarter of 2006. Distribution deliveries also increased in the second quarter to 26.9 billion KWH – a 4.4% increase from the second quarter of 2006. The higher KWH sales and distribution deliveries were primarily attributable to continued customer growth in FirstEnergy’s service territories and weather impacts during the quarter.

Generation Output Record - FirstEnergy set a new second quarter generation output record of 20.4 billion KWH in 2007, which represents a 0.4% increase over the prior record established last year. The generation record was primarily attributable to performance of the fossil generation fleet, which established its best quarterly output ever.

NRC Demand for Information - On May 14, 2007, the NRC issued a Demand for Information related to recent reports prepared for arbitration of an insurance claim for replacing the damaged reactor head at the Davis-Besse Plant in 2002. FENOC responded to the NRC on June 13, 2007.  FirstEnergy officials participated in a public meeting with the NRC on June 27, 2007 to discuss circumstances leading up to the Demand for Information and FENOC’s response. In follow-up discussions, FENOC was requested to provide supplemental information to clarify certain aspects of the Demand for Information response and to provide supplemental details regarding plans to implement the commitments established therein. This supplemental information was submitted to the NRC on July 16, 2007.

Perry Plant Outage - FirstEnergy’s Perry Nuclear Power Plant completed its regularly scheduled refueling outage on May 13, 2007. Major work activities performed on the 1,258 MW facility included replacing approximately one-third of the fuel assemblies in the reactor and two of the three low-pressure turbine rotors in the main generator. On June 29, 2007, Perry began an unplanned outage to replace a 30-ton motor in the reactor recirculation system. In addition to the motor replacement, routine and preventive maintenance and several system inspections will be performed during the outage to assure continued safe and reliable operation of the plant. On July 25, 2007 the plant was returned to service.

Environmental Update - On May 30, 2007, FirstEnergy announced that FGCO plans to install an ECO system on Units 4 and 5 of its R.E. Burger Plant.  Design engineering for the new Burger Plant ECO system will begin in 2007 with an anticipated start-up date in the first quarter of 2011.  The incremental cost installing the system at the Burger Plant instead of Bay Shore Unit 4, as originally planned, is approximately $38 million.

32

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 12 to the consolidated financial statements. Net income by major business segment was as follows:

	Three Months Ended June 30,									Six Months Ended June 30,
							Increase									Increase
	2007			2006			(Decrease)			2007			2006			(Decrease)
	(In millions, except per share amounts)
Net Income (Loss)
By Business Segment:
Energy delivery services	$	207		$	233		$	(26	)	$	425		$	422		$	3
Competitive energy services		142			101			41			240			133			107
Ohio transitional generation services		30			31			(1	)		53			61			(8	)
Other and reconciling adjustments*		(41	)		(61	)		20			(90	)		(91	)		1
Total	$	338		$	304		$	34		$	628		$	525		$	103
Basic Earnings Per Share:
Income from continuing operations	$	1.11		$	0.94		$	0.17		$	2.03		$	1.61		$	0.42
Discontinued operations		-			(0.02	)		0.02			-			(0.02	)		0.02
Net earnings per basic share	$	1.11		$	0.92		$	0.19		$	2.03		$	1.59		$	0.44
Diluted Earnings Per Share:
Income from continuing operations	$	1.10		$	0.93		$	0.17		$	2.01		$	1.60		$	0.41
Discontinued operations		-			(0.02	)		0.02			-			(0.02	)		0.02
Net earnings per diluted share	$	1.10		$	0.91		$	0.19		$	2.01		$	1.58		$	0.43

* Represents other operating segments and reconciling items including interest expense on holding company debt and corporate

  support services revenues and expenses.

33

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

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

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
Second Quarter 2007 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	1,933		$	359		$	612		$	-		$	2,904
Other		162			45			13			(15	)		205
Internal		-			691			-			(691	)		-
Total Revenues		2,095			1,095			625			(706	)		3,109
Expenses:
Fuel and purchased power		879			460			537			(691	)		1,185
Other operating expenses		410			283			87			(30	)		750
Provision for depreciation		100			51			-			8			159
Amortization of regulatory assets		242			-			6			(2	)		246
Deferral of new regulatory assets		(93	)		-			(55	)		-			(148	)
General taxes		155			26			1			7			189
Total Expenses		1,693			820			576			(708	)		2,381
Operating Income		402			275			49			2			728
Other Income (Expense):
Investment income		62			5			-			(37	)		30
Interest expense		(118	)		(47	)		-			(40	)		(205	)
Capitalized interest		2			5			-			-			7
Total Other Expense		(54	)		(37	)		-			(77	)		(168	)
Income From Continuing Operations Before
Income Taxes		348			238			49			(75	)		560
Income taxes		141			96			19			(34	)		222
Net Income	$	207		$	142		$	30		$	(41	)	$	338

34

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
Second Quarter 2006 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	1,646		$	338		$	569		$	-		$	2,553
Other		127			46			6			19			198
Internal		6			623			-			(629	)		-
Total Revenues		1,779			1,007			575			(610	)		2,751
Expenses:
Fuel and purchased power		690			434			496			(629	)		991
Other operating expenses		363			289			53			13			718
Provision for depreciation		89			48			-			7			144
Amortization of regulatory assets		197			-			4			-			201
Deferral of new regulatory assets		(113	)		-			(33	)		-			(146	)
General taxes		144			23			2			4			173
Total Expenses		1,370			794			522			(605	)		2,081
Operating Income		409			213			53			(5	)		670
Other Income (Expense):
Investment income		81			2			-			(52	)		31
Interest expense		(101	)		(50	)		-			(27	)		(178	)
Capitalized interest		4			3			-			-			7
Subsidiaries' preferred stock dividends		(5	)		-			-			3			(2	)
Total Other Expense		(21	)		(45	)		-			(76	)		(142	)
Income From Continuing Operations Before
Income Taxes		388			168			53			(81	)		528
Income taxes		155			67			22			(28	)		216
Income from continuing operations		233			101			31			(53	)		312
Discontinued operations		-			-			-			(8	)		(8	)
Net Income	$	233		$	101		$	31		$	(61	)	$	304
Changes Between Second Quarter 2007 and
Second Quarter 2006 Financial Results
Increase (Decrease)
Revenues:
External
Electric	$	287		$	21		$	43		$	-		$	351
Other		35			(1	)		7			(34	)		7
Internal		(6	)		68			-			(62	)		-
Total Revenues		316			88			50			(96	)		358
Expenses:
Fuel and purchased power		189			26			41			(62	)		194
Other operating expenses		47			(6	)		34			(43	)		32
Provision for depreciation		11			3			-			1			15
Amortization of regulatory assets		45			-			2			(2	)		45
Deferral of new regulatory assets		20			-			(22	)		-			(2	)
General taxes		11			3			(1	)		3			16
Total Expenses		323			26			54			(103	)		300
Operating Income		(7	)		62			(4	)		7			58
Other Income (Expense):
Investment income		(19	)		3			-			15			(1	)
Interest expense		(17	)		3			-			(13	)		(27	)
Capitalized interest		(2	)		2			-			-			-
Subsidiaries' preferred stock dividends		5			-			-			(3	)		2
Total Other Income		(33	)		8			-			(1	)		(26	)
Income From Continuing Operations Before
Income Taxes		(40	)		70			(4	)		6			32
Income taxes		(14	)		29			(3	)		(6	)		6
Income from continuing operations		(26	)		41			(1	)		12			26
Discontinued operations		-			-			-			8			8
Net Income	$	(26	)	$	41		$	(1	)	$	20		$	34

35

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

Net income decreased $26 million (or 11%) to $207 million in the second quarter of 2007 compared to $233 million in the second quarter of 2006, primarily due to increased purchased power costs, higher other operating expenses and increased depreciation and amortization, partially offset by higher revenues.

Revenues –

The increase in total revenues resulted from the following sources:

	Three Months Ended
	June 30,
Revenues by Type of Service	2007		2006		Increased
	(In millions)
Distribution services	$	948	$	913	$	35
Generation sales:
Retail		756		645		111
Wholesale		148		49		99
Total generation sales		904		694		210
Transmission		194		124		70
Other		49		48		1
Total Revenues	$	2,095	$	1,779	$	316

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

Electric Distribution Deliveries
Residential	9.2	%
Commercial	4.9	%
Industrial	(0.2	)%
Total Distribution Deliveries	4.4	%

The increase in electric distribution deliveries to customers was primarily due to higher weather-related usage during the second quarter of 2007 compared to the same period of 2006 (heating degree days increased by 15.8% and cooling degree days increased by 39.3%). The higher revenues from distribution deliveries were partially offset principally 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 $210 million increase in non-affiliated generation sales in 2007 compared to 2006:

Sources of Change in Generation Sales	Increase
	(In millions)
Retail:
Effect of 1% increase in customer usage	$	6
Change in prices		105
		111
Wholesale:
Effect of 131% increase in KWH sales		64
Change in prices		35
		99
Net Increase in Generation Sales	$	210

The increase in retail generation prices during the second 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 $70 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the January 2007 PPUC authorization for transmission cost recovery. Met-Ed and Penelec defer the difference between revenues from their transmission rider and transmission costs incurred, with no material effect to current period earnings.

36

Expenses –

The net increases in revenues discussed above were more than offset by a $323 million increase in expenses due to the following:

· Purchased power costs were $187million higher in the second quarter of 2007 due to higher unit prices and volumes purchased. The increased unit prices reflected the effect of higher JCP&L purchased power unit prices resulting from the BGS auction. The increased KWH purchases in 2007 were due to higher customer usage and 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	$	99
Change due to increased volume		43
Decrease in NUG costs deferred		45
Net Increase in Purchased Power Costs	$	187

· Other operating expenses increased $47million due to the net effects of:

-   An increase of $49million in transmission expenses, resulting primarily from higher congestion costs ($47 million);

-   A decrease in miscellaneous operating expenses of $12million primarily due to reduced billings for employee benefits from FESC; and

-   An increase in operation and maintenance expenses of $12million primarily due to increased labor costs devoted to operating activities ($22 million) partially offset by lower employee benefit costs ($10 million);

· Amortization of regulatory assets increased $45million compared to 2006 due primarily to recovery of deferred BGS costs through higher NUGC revenues for JCP&L as discussed above; and

· The deferral of new regulatory assets during the second quarter of 2007 was $20 million lower than 2006 due in part to $25 million in reduced deferrals of transmission related PJM costs. The higher deferral in the second quarter of 2006 was attributable to the deferral of first quarter costs following authorization by the PPUC in May 2006 (see Note 10). The reduction in deferred PJM costs was partially offset by interest earned on the RCP Distribution Deferral.

Other Income and Expense –

Other income decreased $33 million in 2007 compared to the second quarter of 2006 primarily due to lower interest income of $19 million resulting from the repayment of notes receivable from affiliates since the second quarter of 2006, and increased interest expense of $17 million related in part to new debt issuances by CEI and JCP&L.

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

Net income of $30million in the second quarter of 2007 did not differ significantly from $31million in the same period last year. Higher generation revenues were offset by higher operating expenses, primarily for purchased power.

37

Revenues –

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

	Three Months Ended
	June 30,
Revenues by Type of Service	2007		2006		Increase
	(In millions)
Generation sales:
Retail	$	544	$	504	$	40
Wholesale		2		2		-
Total generation sales		546		506		40
Transmission		79		69		10
Total Revenues	$	625	$	575	$	50

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)
Retail:
Effect of 4.4% increase in customer usage	$	22
Change in prices		18
Total Increase in Retail Generation Sales	$	40

The increase in generation sales was primarily due to higher weather-related usage in the second quarter of 2007 as discussed above and reduced customer shopping. Average prices increased primarily due to higher composite unit prices for returning customers.

Expenses -

Purchased power costs were $41 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 (Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to decreased unit costs	$	(5	)
Change due to volume		2
		(3	)
Purchases from FES:
Change due to increased unit costs		23
Change due to volume		21
		44
Total Increase in Purchased Power Costs	$	41

The increase in KWH purchases 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.

Other operating expenses increased $34 million due primarily 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.

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

Net income for this segment was $142million in the second quarter of 2007 compared to $101million in the same period last year. An improvement in gross generation margin and lower other operating expenses was partially offset by an increase in other expenses.

38

Revenues –

Total revenues increased $88million in the second quarter of 2007 compared to the same period in 2006. This increase primarily resulted from higher unit prices from affiliated generation sales to the Ohio Companies, 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. 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 requirements 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 KWH sales. Factors contributing to the revenue increase from PSA sales to the Ohio Companies are discussed under the purchased power costs analysis in the Ohio Transitional Generation Services results above. The higher KWH sales to the Pennsylvania affiliates 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.

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

	Three Months Ended
	June 30,				Increase
Revenues By Type of Service	2007		2006		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	185	$	136	$	49
Wholesale		174		202		(28	)
Total Non-Affiliated Generation Sales		359		338		21
Affiliated Generation Sales		691		623		68
Transmission		22		29		(7	)
Other		23		17		6
Total Revenues	$	1,095	$	1,007	$	88

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 20% increase in sales volume	$	27
Change in prices		22
		49
Wholesale:
Effect of 28% decrease in KWH sales		(56	)
Change in prices		28
		(28	)
Net Increase in Non-Affiliated Generation Sales	$	21

Source of Change in Affiliated Generation Sales	Increase (Decrease)
	(In millions)
Ohio Companies:
Effect of 4% increase in KWH sales	$	21
Change in prices		23
		44
Pennsylvania Companies:
Effect of 18% increase in KWH sales		25
Change in prices		(1	)
		24
Net Increase in Affiliated Generation Sales	$	68

39

Expenses -

Total operating expenses were $26 million higher in the second quarter of 2007 due to the following factors:

· Purchased power costs increased $32million due to higher unit prices;

· Nuclear production costs increased $6 million, caused in part by expenditures related to the Perry refueling outage ($15 million), partially offset by reduced labor costs ($7 million) due to more labor devoted to capital projects in 2007 and reduced employee benefits costs ($3 million);

· Expenses related to marking commodity contracts to market value were $5 million higher due to a $1 million unrealized loss on purchased power hedges and the absence of a $4 million gain on gas hedges recognized in 2006; and

· Higher depreciation expense of $3 million from property additions.

Partially offsetting the increases were the following:

· MISO/PJM transmission expenses were $8 million lower due to reduced Revenue Sufficiency Guarantee charges ($19 million) partially offset by higher point-to-point transmission and congestion charges;

· Fossil operating costs were $9 million lower due to the absence of asbestos removal costs of $4 million included in 2006 results and reduced employee benefit costs; and

· Fuel costs were $6 million lower due to a $14 million coal inventory adjustment and a $6 million reduction in emission allowance costs. Partially offsetting these decreases were $11 million of increased natural gas, coal and nuclear fuel consumption, due to increased generation, and $3 million of increases in other fuel costs.

Other Income –

Investment income in the second quarter of 2007 was $3million higher than the 2006 period primarily due to increased earnings on nuclear decommissioning trust investments (net of an $8 million impairment) while interest expense was $3 million lower due to reduced short-term borrowings.

Other – Second Quarter 2007 Compared to Second 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 $20million increase in FirstEnergy’s net income in the second quarter of 2007 compared to the same quarter of 2006. The increase was primarily due to the absence of an $8million loss included in 2006 results from discontinued operations (see Note 3), the absence of $3 million in subsidiary preferred stock dividends and reduced capital stock taxes of $3 million.

40

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

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

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
First Six Months 2007 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	3,808		$	635		$	1,226		$	-		$	5,669
Other		327			97			19			(30	)		413
Internal		-			1,404			-			(1,404	)		-
Total Revenues		4,135			2,136			1,245			(1,434	)		6,082
Expenses:
Fuel and purchased power		1,722			907			1,081			(1,404	)		2,306
Other operating expenses		819			588			138			(46	)		1,499
Provision for depreciation		199			102			-			14			315
Amortization of regulatory assets		487			-			11			(1	)		497
Deferral of new regulatory assets		(217	)		-			(75	)		-			(292	)
General taxes		320			55			2			15			392
Total Expenses		3,330			1,652			1,157			(1,422	)		4,717
Operating Income		805			484			88			(12	)		1,365
Other Income (Expense):
Investment income		132			8			1			(78	)		63
Interest expense		(227	)		(100	)		(1	)		(62	)		(390	)
Capitalized interest		4			8			-			-			12
Total Other Expense		(91	)		(84	)		-			(140	)		(315	)
Income From Continuing Operations Before
Income Taxes		714			400			88			(152	)		1,050
Income taxes		289			160			35			(62	)		422
Net Income	$	425		$	240		$	53		$	(90	)	$	628

41

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
First Six Months 2006 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	3,314		$	642		$	1,108		$	-		$	5,064
Other		256			96			10			30			392
Internal		14			1,235			-			(1,249	)		-
Total Revenues		3,584			1,973			1,118			(1,219	)		5,456
Expenses:
Fuel and purchased power		1,383			901			954			(1,249	)		1,989
Other operating expenses		729			634			109			(1	)		1,471
Provision for depreciation		185			94			-			13			292
Amortization of regulatory assets		413			-			9			-			422
Deferral of new regulatory assets		(168	)		-			(58	)		-			(226	)
General taxes		302			49			2			13			366
Total Expenses		2,844			1,678			1,016			(1,224	)		4,314
Operating Income		740			295			102			5			1,142
Other Income (Expense):
Investment income		164			17			-			(107	)		74
Interest expense		(201	)		(96	)		(1	)		(45	)		(343	)
Capitalized interest		7			6			-			1			14
Subsidiaries' preferred stock dividends		(7	)		-			-			3			(4	)
Total Other Expense		(37	)		(73	)		(1	)		(148	)		(259	)
Income From Continuing Operations Before
Income Taxes		703			222			101			(143	)		883
Income taxes		281			89			40			(58	)		352
Income from continuing operations		422			133			61			(85	)		531
Discontinued operations		-			-			-			(6	)		(6	)
Net Income	$	422		$	133		$	61		$	(91	)	$	525
Changes Between First Six Months 2007
and First Six Months 2006
Financial Results Increase (Decrease)
Revenues:
External
Electric	$	494		$	(7	)	$	118		$	-		$	605
Other		71			1			9			(60	)		21
Internal		(14	)		169			-			(155	)		-
Total Revenues		551			163			127			(215	)		626
Expenses:
Fuel and purchased power		339			6			127			(155	)		317
Other operating expenses		90			(46	)		29			(45	)		28
Provision for depreciation		14			8			-			1			23
Amortization of regulatory assets		74			-			2			(1	)		75
Deferral of new regulatory assets		(49	)		-			(17	)		-			(66	)
General taxes		18			6			-			2			26
Total Expenses		486			(26	)		141			(198	)		403
Operating Income		65			189			(14	)		(17	)		223
Other Income (Expense):
Investment income		(32	)		(9	)		1			29			(11	)
Interest expense		(26	)		(4	)		-			(17	)		(47	)
Capitalized interest		(3	)		2			-			(1	)		(2	)
Subsidiaries' preferred stock dividends		7			-			-			(3	)		4
Total Other Income		(54	)		(11	)		1			8			(56	)
Income From Continuing Operations Before
Income Taxes		11			178			(13	)		(9	)		167
Income taxes		8			71			(5	)		(4	)		70
Income from continuing operations		3			107			(8	)		(5	)		97
Discontinued operations		-			-			-			6			6
Net Income	$	3		$	107		$	(8	)	$	1		$	103

42

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

Net income increased $3 million (or 1%) to $425 million in the first six months of 2007 compared to $422 million in the first six months of 2006, primarily due to increased revenues partially offset by higher operating expenses and lower investment income.

Revenues –

The increase in total revenues resulted from the following sources:

	Six Months Ended
	June 30,
Revenues by Type of Service	2007		2006		Increase
	(In millions)
Distribution services	$	1,892	$	1,848	$	44
Generation sales:
Retail		1,476		1,281		195
Wholesale		281		105		176
Total generation sales		1,757		1,386		371
Transmission		376		247		129
Other		110		103		7
Total Revenues	$	4,135	$	3,584	$	551

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

Electric Distribution Deliveries
Residential	8.0	%
Commercial	4.6	%
Industrial	-
Total Distribution Deliveries	4.2	%

The increase in electric distribution deliveries to customers was primarily due to higher weather-related usage during the first six months of 2007 compared to the same period of 2006 (heating degree days increased by 15.4% and cooling degree days increased by 39.8%). The higher revenues from increased distribution deliveries were offset principally 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 $371 million increase in non-affiliated generation sales revenues in 2007 compared to 2006:

Sources of Change in Generation Sales	Increase
	(In millions)
Retail:
Effect of 0.6% increase in customer usage	$	8
Change in prices		187
		195
Wholesale:
Effect of 135% increase in KWH sales		141
Change in prices		35
		176
Net Increase in Generation Sales	$	371

The increase in retail generation prices during the first six 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.

Transmission revenues increased $129 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the January 2007 PPUC authorization for transmission cost recovery. Met-Ed and Penelec defer the difference between revenues from their transmission rider and transmission costs incurred, with no material effect on current period earnings

43

Expenses –

The net increases in revenues discussed above were partially offset by a $486 million increase in expenses due to the following:

· Purchased power costs were $339million higher in the first six months of 2007 due to higher unit costs and volumes purchased. The increased unit prices reflected the effect of higher JCP&L purchased power unit costs resulting from the BGS auction process. The increased KWH purchases in 2007 were due in part to higher customer usage and 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	$	168
Change due to increased volume		128
Decrease in NUG costs deferred		43
Net Increase in Purchased Power Costs	$	339

· Other operating expenses increased $90million due to the net effects of:

-   An increase of $101million in MISO and PJM transmission expenses, resulting primarily from higher congestion costs;

-   A decrease in miscellaneous operating expenses of $18million primarily due to reduced billings for employee benefits from FESC; and

-   An increase in operation and maintenance expenses of $10million primarily due to reduced employee benefits applicable to construction activities and storm-related costs;

· Amortization of regulatory assets increased $75million compared to 2006 due primarily to recovery of deferred BGS costs through higher NUGC rates for JCP&L as discussed above; and

· The deferral of new regulatory assets during the first six months of 2007 was $49 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 deferrals of PJM transmission expenses of $10 million and increased RCP Distribution Deferrals of $10 million.

Other Income and Expense –

Other income decreased $54million in 2007 compared to the first six months of 2006 primarily due to lower interest income of $32million resulting from the repayment of notes receivable from affiliates since the second quarter of 2006 and increased interest expense of $26million related to new debt issuances by CEI and JCP&L.

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

Net income for this segment decreased to $53million in the first six months of 2007 from $61 million in the same period last year. Higher generation revenues were offset by higher operating expenses, primarily for purchased power.

44

Revenues –

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

	Six Months Ended
	June 30,				Increase
Revenues by Type of Service	2007		2006		(Decrease)
	(In millions)
Generation sales:
Retail	$	1,090	$	976	$	114
Wholesale		4		9		(5	)
Total generation sales		1,094		985		109
Transmission		150		132		18
Other		1		1		-
Total Revenues	$	1,245	$	1,118	$	127

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 6% increase in customer usage	$	54
Change in prices		60
Total Increase in Retail Generation Sales	$	114

The increase in generation sales was primarily due to higher weather-related usage in the first six 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 2percentage points from the same period last year.

Expenses -

Purchased power costs were $127million higher due primarily to higher unit prices for power purchased from FES. The factors contributing to the higher costs are summarized in the following table:

Source of Change in Purchased Power	Increase
	(In millions)
Purchases from non-affiliates:
Change due to increased unit costs	$	7
Change due to volume purchased		1
		8
Purchases from FES:
Change due to increased unit costs		76
Change due to volume purchased		43
		119
Total Increase in Purchased Power Costs	$	127

The increase in KWH purchases 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.

Other operating expenses increased $29 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.

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

Net income for this segment was $240million in the first six months of 2007 compared to $133million in the same period last year. This increase reflects an improvement in gross generation margin and lower other operating expenses, which were partially offset by increased depreciation, general taxes and reduced investment income.

45

Revenues –

Total revenues increased $163million in the first six 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, which was partially offset by lower non-affiliated wholesale sales.

The higher retail revenues resulted from increased sales in both the MISO and PJM markets. 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 KWH sales. Factors contributing to the revenue increase from PSA sales to the Ohio Companies are discussed under the purchased power costs analysis in the Ohio Transitional Generation Services results above. The higher KWH sales to the Pennsylvania affiliates 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:

	Six Months Ended
	June 30,				Increase
Revenues by Type of Service	2007		2006		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	359	$	267	$	92
Wholesale		276		375		(99	)
Total Non-Affiliated Generation Sales		635		642		(7	)
Affiliated Generation Sales		1,404		1,235		169
Transmission		45		64		(19	)
Other		52		32		20
Total Revenues	$	2,136	$	1,973	$	163

Transmission revenues decreased $19 million due to reduced retail load in the MISO market, lower transmission rates and reduced FTR 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 19% increase in sales volume	$	51
Change in prices		41
		92
Wholesale:
Effect of 31% decrease in KWH sales		(118	)
Change in prices		19
		(99	)
Net Decrease in Non-Affiliated Generation Sales	$	(7	)

Source of Change in Affiliated Generation Sales	Increase
	(In millions)
Ohio Companies:
Effect of 5% increase in KWH sales	$	43
Change in prices		77
		120
Pennsylvania Companies:
Effect of 14% increase in KWH sales		40
Change in prices		9
		49
Net Increase in Affiliated Generation Sales	$	169

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Expenses -

Total expenses were $26 million lower in the first six months of 2007 due to the following factors:

· Fuel costs were $26 million lower primarily due to reduced coal costs and emission allowance costs offset by increases in nuclear fuel and natural gas consumption. Coal costs were reduced due to a $14 million inventory adjustment and $35 million of reduced coal consumption reflecting lower generation, partially offset by a $19 million increase in coal prices. Reduced emission allowance costs ($12 million) were more than offset by increased natural gas costs ($6 million) and nuclear fuel costs ($9 million) due to increased generation and higher prices; and

·   Nuclear operating costs were $58 million lower due to fewer outages in 2007 compared to 2006 and reduced employee benefit costs.

Partially offsetting the lower costs were the following:

· Purchased power costs increased $31 million due primarily to higher volumes purchased;

· Higher fossil operating costs of $12 million due to increased labor costs;

· Higher depreciation expenses of $8 million due to property additions; and

· Higher general taxes of $5 million.

Other Income –

Investment income in the first six months of 2007 was $11million lower than the 2006 period primarily due to decreased earnings on nuclear decommissioning trust investments (including a $12 million impairment).

Other – First Six Months of 2007 Compared to First Six 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 $1million increase in FirstEnergy’s net income in the first six months of 2007. The increase was caused by the absence of a $6million loss included in 2006 results from discontinued operations (see Note 3) offset by increased interest expense in 2007 compared to 2006 due to higher short-term borrowings.

CAPITAL RESOURCES AND LIQUIDITY

FirstEnergy’s business is capital intensive, requiring considerable capital 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 primarily 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 given 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 six months of 2007, FirstEnergy received $637 million of cash dividends and return of capital from its subsidiaries and paid $311 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.

47

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, including $500 million from bridge loan facilities that have since been repaid.

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in the Bruce Mansfield Plant Unit 1, representing 779 MW of net demonstrated capacity. The purchase price of approximately $1.329 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 trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements.  The transaction will be classified as a financing under GAAP until FGCO’s and 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 are satisfied, at which time it is expected to be classified as an operating lease under GAAP. 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 accelerated share repurchase program and $300 million pension contribution. FGCO continues to operate the plant. CEI has an existing sale and leaseback arrangement for the remaining 51 MW portion of Bruce Mansfield Unit 1. This transaction generated tax capital gains of approximately $830 million, a substantial portion of which will be offset by existing tax capital loss carryforwards.  FirstEnergy will reduce its tax loss carryforward valuation allowances in the third quarter of 2007 and anticipates an immaterial impact to net income as the majority of the unrecognized tax benefits will reduce goodwill.

As of June 30, 2007, FirstEnergy had $37 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 regulated services and power supply management services businesses (see Results of Operations above). Net cash provided from operating activities was $131 million and $485 million in the first six months of 2007 and 2006, respectively, summarized as follows:

	Six Months Ended
	June 30,
Operating Cash Flows	2007			2006
	(In millions)
Net income	$	628		$	525
Non-cash charges		277			260
Pension trust contribution		(300	)		-
Working capital and other		(474	)		(300	)
	$	131		$	485

Net cash provided from operating activities decreased by $354 million in the first six months of 2007 compared to the first six months of 2006 primarily due to a $300 million pension trust contribution in 2007 and $174 million from working capital charges, partially offset by a $103 million increase in net income (see Results of Operations above). The decrease from working capital and other changes primarily resulted from a $365 million increase in receivables due to higher sales, partially offset by $93 million from reduced materials and supplies inventories and $68 million of decreased payments for accounts payable.

Cash Flows From Financing Activities

In the first six months of 2007, cash provided from financing activities was $454 million compared to $618 million in the first six months of 2006. The decrease was primarily due to the repurchase of common stock in 2007, partially offset by higher short-term borrowings. The following table summarizes security issuances and redemptions.

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	Six Months Ended
	June 30,
Securities Issued or Redeemed	2007		2006
	(In millions)
New issues
Pollution control notes	$	-	$	253
Secured notes		-		200
Unsecured notes		800		600
	$	800	$	1,053
Redemptions
First mortgage bonds	$	275	$	1
Pollution control notes		-		307
Senior secured notes		43		177
Unsecured notes		153		-
Common stock		918		-
Preferred stock		-		30
	$	1,389	$	515
Short-term borrowings, net	$	1,308	$	371

FirstEnergy had approximately $2.4 billion of short-term indebtedness as of June 30, 2007 compared to approximately $1.1 billion as of December 31, 2006. This increase resulted from interim funding of FirstEnergy’s $900 million share repurchase program and $300 million pension contribution in the first half of the year. Available bank borrowing capability as of June 30, 2007 included the following:

Borrowing Capability (In millions)
Short-term credit facilities(1)	$	3,220
Accounts receivable financing facilities		550
Utilized		(2,413	)
LOCs		(339	)
Net	$	1,018
(1) Includes the  $2.75 billion revolving credit facility described below, a $100 million revolving credit facility that expires in December 2009, a $20 million uncommitted line of credit and $350 million bridge loan facilities.

As of June 30, 2007, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.9 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 $463 million, $515 million and $127 million, respectively, as of June 30, 2007.  Because 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, it is no longer required to issue FMBs as collateral for senior notes and therefore is not limited as to the amount of senior notes it may issue.

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

As of June 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 June 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.

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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			40
CEI		250	(3)		500
TE		250	(3)		500
JCP&L		425			431
Met-Ed		250			250	(4)
Penelec		250			250	(4)
FES		250			-	(2)
ATSI		-	(5)		50

⁽¹⁾ As of June 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 ($287 million unused as of June 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 June 30, 2007, FirstEnergy and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:

Borrower
FirstEnergy	61	%
OE	48	%
Penn	24	%
CEI	60	%
TE	56	%
JCP&L	32	%
Met-Ed	46	%
Penelec	38	%
FES	57	%

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.

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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 six months of 2007 was 5.64% for both the regulated and the unregulated companies' money pools.

FirstEnergy’s access to capital markets and costs of financing are influenced by the ratings of its securities.  The following table displays FirstEnergy’s and the Companies’ securities ratings as of June 30, 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 stable.  The rating outlook from Fitch on CEI and Toledo Edison is positive and stable on all other operating companies.

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

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Cash Flows From Investing Activities

Net cash flows used in investing activities resulted principally from property additions. Energy delivery services expenditures for property additions primarily include expenditures related to transmission and distribution facilities. Capital expenditures by the competitive energy services segment are principally generation-related. The following table summarizes investing activities for the second quarter of 2007 and 2006 by segment:

Summary of Cash Flows	Property
Used for Investing Activities	Additions			Investments			Other			Total
Sources (Uses)	(In millions)
Six Months Ended June 30, 2007
Energy delivery services	$	(400	)	$	84		$	-		$	(316	)
Competitive energy services		(263	)		16			(1	)		(248	)
Other		(34	)		(22	)		(3	)		(59	)
Inter-Segment reconciling items		-			(15	)		-			(15	)
Total	$	(697	)	$	63		$	(4	)	$	(638	)
Six Months Ended June 30, 2006
Energy delivery services	$	(370	)	$	198		$	(6	)	$	(178	)
Competitive energy services		(347	)		(20	)		(4	)		(371	)
Other		(22	)		46			4			28
Inter-Segment reconciling items		-			(63	)		-			(63	)
Total	$	(739	)	$	161		$	(6	)	$	(584	)

Net cash used for investing activities in the first six months of 2007 increased by $54 million compared to the same period of 2006. The increase was principally due to a $64 million decrease in cash provided from cash investments, primarily from the use of restricted cash investments to repay debt during 2006.  Partially offsetting the decrease in cash provided from cash investments was a $42 million decrease in property additions which reflects the replacement of the steam generators and reactor head at Beaver Valley Unit 1 in 2006.

During the second half of 2007, capital requirements for property additions and capital leases are expected to be $820 million. FirstEnergy and the Companies have additional requirements of approximately $172 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 $7.9 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 $804 million and $102 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 June 30, 2007, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.1 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)	$	800
LOC (2)		864
Other (3)		587
		2,251
Surety Bonds		95
LOC (4)(5)		1,737
Total Guarantees and Other Assurances	$	4,083

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

⁽²⁾ LOC’s issued on behalf of FGCO and NGC in support of pollution control revenue bonds with various maturities, which are recognized 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 $339 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facility and an additional $779 million outstanding in support of pollution control revenue bonds issued with various maturities on behalf of FGCO and NGC, which are recognized on FirstEnergy’s consolidated balance sheets.

⁽⁵⁾ 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 June 30, 2007, FirstEnergy’s maximum exposure under these collateral provisions was $421 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 June 30, 2007), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.

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.

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OFF-BALANCE SHEET ARRANGEMENTS

The Ohio Companies have obligations that are not included on FirstEnergy’s Consolidated Balance Sheets related to the 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 June 30, 2007, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.1 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 six months ended June 30, 2007 is summarized in the following table:

	Three Months Ended									Six Months Ended
Increase (Decrease) in the Fair Value	June 30, 2007									June 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	$	(1,028	)	$	1		$	(1,027	)	$	(1,140	)	$	(17	)	$	(1,157	)
Additions/change in value of existing contracts		91			(11	)		80			197			(6	)		191
Settled contracts		92			(2	)		90			98			11			109
Outstanding net liability at end of period (1)		(845	)		(12	)		(857	)		(845	)		(12	)		(857	)
Non-commodity Net Liabilities at End of Period:
Interest rate swaps (2)		-			(24	)		(24	)		-			(24	)		(24	)
Net Liabilities - Derivative Contracts at End of Period	$	(845	)	$	(36	)	$	(881	)	$	(845	)	$	(36	)	$	(881	)
Impact of Changes in Commodity Derivative Contracts(3)
Income Statement effects (pre-tax)	$	(2	)	$	-		$	(2	)	$	-		$	-		$	-
Balance Sheet effects:
Other comprehensive income (pre-tax)	$	-		$	(13	)	$	(13	)	$	-		$	5		$	5
Regulatory assets (net)	$	(185	)	$	-		$	(185	)	$	(295	)	$	-		$	(295	)

⁽¹⁾ Includes $841 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 June 30, 2007 as follows:

Balance Sheet Classification	Non-Hedge			Hedge			Total
	(In millions)
Current-
Other assets	$	-		$	35		$	35
Other liabilities		(4	)		(50	)		(54	)
Non-Current-
Other deferred charges		37			24			61
Other non-current liabilities		(878	)		(45	)		(923	)
Net liabilities	$	(845	)	$	(36	)	$	(881	)

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 June 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)	$	(1	)	$	-		$	-		$	-		$	-		$	-		$	(1	)
Other external sources(3)		(112	)		(221	)		(172	)		(146	)		-			-			(651	)
Prices based on models		-			-			-			-			(100	)		(105	)		(205	)
Total(4)	$	(113	)	$	(221	)	$	(172	)	$	(146	)	$	(100	)	$	(105	)	$	(857	)

⁽¹⁾     For the last two quarters of 2007.

⁽²⁾     Exchange traded.

⁽³⁾     Broker quote sheets.

   ⁽⁴⁾   Includes $841 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 June 30, 2007. Based on derivative contracts held as of June 30, 2007, an adverse 10% change in commodity prices would decrease net income by approximately $9 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 six 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 current period.  As of June 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 6.06%.

55

	June 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	$	(2	)	$	100		2008	$	(2)
		50		2010		(1	)		50		2010		(1)
		300		2013		(13	)		300		2013		(6)
		150		2015		(14	)		150		2015		(10)
		-		2025		-			50		2025		(2)
		-		2031		-			100		2031		(6)
	$	600			$	(30	)	$	750			$	(27)

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 the 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 six months of 2007, FirstEnergy terminated forward swaps with an aggregate notional value of $950 million. FirstEnergy paid $2 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 June 30, 2007, FirstEnergy had outstanding forward swaps with an aggregate notional amount of $250 million and an aggregate fair value of $6 million.

	June 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	$	1	$	25		2015	$	-
		150		2017		2		200		2017		(4	)
		25		2018		-		25		2018		(1	)
		50		2020		3		50		2020		1
	$	250			$	6	$	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 June 30, 2007 and December 31, 2006. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $136 million reduction in fair value as of June 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 June 30, 2007, the largest credit concentration with one party (currently rated investment grade) represented 11% 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 June 30, 2007.

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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;

·    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 $219 million as of June 30, 2007 (JCP&L - $103 million, Met-Ed - $34 million and Penelec - $82 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:

	June 30,		December 31,		Increase
Regulatory Assets*	2007		2006		(Decrease)
	(In millions)
OE	$	733	$	741	$	(8	)
CEI		863		855		8
TE		230		248		(18	)
JCP&L		1,825		2,152		(327	)
Met-Ed		464		409		55
ATSI		40		36		4
Total	$	4,155	$	4,441	$	(286	)

 * Penelec had net regulatory liabilities of approximately $74 million and $96 million as of June 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:

	June 30,			December 31,			Increase
Regulatory Assets By Source	2007			2006			(Decrease)
	(In millions)
Regulatory transition costs	$	2,731		$	3,266		$	(535	)
Customer shopping incentives		562			603			(41	)
Customer receivables for future income taxes		259			217			42
Societal benefits charge		(2	)		11			(13	)
Loss on reacquired debt		59			43			16
Employee postretirement benefits		43			47			(4	)
Nuclear decommissioning, decontamination
and spent fuel disposal costs		(114	)		(145	)		31
Asset removal costs		(173	)		(168	)		(5	)
Property losses and unrecovered plant costs		13			19			(6	)
MISO/PJM transmission costs		292			213			79
Fuel costs - RCP		154			113			41
Distribution costs - RCP		246			155			91
Other		85			67			18
Total	$	4,155		$	4,441		$	(286	)

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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 partly to amend the Federal Power Act with Section 215, which requires that an ERO establish and enforce reliability standards for the bulk-power system, subject to review of 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.

While the FERC approved 83 of the 107 reliability standards proposed by NERC, the FERC has directed NERC to submit improvements to 56 of them, endorsing NERC's process for developing reliability standards and its associated work plan. On May 4, 2007, NERC also submitted 24 proposed Violation Risk Factors.  The FERC issued an order approving 22 of those factors on June 26, 2007. Further, NERC adopted eight cyber security standards that became effective on June 1, 2006 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 assessment by February 12, 2007. The standards remain pending before the FERC.  On July 20, 2007, the FERC issued a NOPR proposing to adopt eight Critical Infrastructure Protection Reliability Standards.  Comments will not be due to the FERC until September or October of 2007.

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 will eventually adopt stricter NERC reliability 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.

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Ohio

On October 21, 2003, the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to the PUCO’s concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming the PUCO's order in all respects, except it remanded back to the PUCO the matter of ensuring the availability of sufficient means for customer participation in the marketplace. The RSP contained a provision that permitted the Ohio Companies to withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies have 30 days from the final order or decision to provide notice of termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding on Remand. In their Request, the Ohio Companies provided notice of termination to those provisions of the RSP subject to termination, subject to being withdrawn, and also set forth a framework for addressing the Supreme Court of Ohio’s findings on customer participation. If the PUCO approves a resolution to the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and considered to be null and void. On July 20, 2006, the OCC and NOAC also submitted to the PUCO a conceptual proposal addressing the issue raised by the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry directing the Ohio Companies to file a plan in a new docket to address the Court’s concern. The Ohio Companies filed their RSP Remand CBP on September 29, 2006. Initial comments were filed on January 12, 2007 and reply comments were filed on January 29, 2007. In their reply comments the Ohio Companies described the highlights of a new tariff offering they would be willing to make available to customers that would allow customers to purchase renewable energy certificates associated with a renewable generation source, subject to PUCO approval. On May 29, 2007, the Ohio Companies, together with the PUCO Staff and the OCC, filed a stipulation with the PUCO agreeing to offer a standard bid product and a green resource tariff product. The stipulation is currently pending before the PUCO. No further proceedings are scheduled at this time.

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 Period	OE		CEI		TE		Total   Ohio
	(In millions)
2007	$	179	$	108	$	93	$	380
2008		208		124		119		451
2009		-		216		-		216
2010		-		273		-		273
Total Amortization	$	387	$	721	$	212	$	1,320

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 provided an update 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 late 2007. The PUCO order is expected to be issued by March 9, 2008. The new rates, subject to evidentiary hearings and approval at the PUCO, 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 Ohio Companies requested that the PUCO issue an order by November 1, 2007, to provide sufficient time to conduct the bidding process. The PUCO has scheduled a technical conference for August 16, 2007.

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 costs during the term of these agreements with FES.

On April 7, 2006, the parties entered into a tolling agreement that arose from FES’ notice to Met-Ed and Penelec that FES elected to exercise its right to terminate the partial requirements agreement effective midnight December 31, 2006. On November 29, 2006, Met-Ed, Penelec and FES agreed to suspend the April 7 tolling agreement pending resolution of the PPUC’s proceedings regarding the Met-Ed and Penelec comprehensive transition rate cases filed April 10, 2006, described below. Separately, 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 substantially exceed 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 tolling, suspension and 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.

Met-Ed and Penelec made a comprehensive 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 in accordance with the April 7, 2006 tolling agreement described above. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs, but only for those 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 the merger savings, with the comprehensive transmission rate filing case.

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The PPUC entered its Opinion and Order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, 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 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 by all parties. Responsive briefs are due August 20, 2007, with reply briefs due September 4, 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 June 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 $493 million and $127 million, respectively. $82 million of Penelec’s deferral is subject to final resolution of an IRS settlement associated with NUG trust fund proceeds. 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 late 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 would be provided through an hourly-priced service provided by Penn. Quarterly reconciliation of the differences between the costs of supply and revenues from customers is also proposed. The PPUC is requested to act on the proposal no later than November 2007 for the initial RFP to take place in January 2008.

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On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation 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 will be 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 June 30, 2007, the accumulated deferred cost balance totaled approximately $392 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 Energy Master Plan (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;

·       Unit prices for electricity should remain 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.

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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 August 1, 2007, the NJBPU approved publication of a formal proposal in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following a period for public comment.  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 third 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 and Electric Company 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 American Electric Power Company, Inc., 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.

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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 maintain existing transmission rates between MISO and PJM.  If accepted 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 transmission facilities across the entire MISO footprint be maintained.  All of these filings were supported by the majority of transmission owners in either MISO or PJM.

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 transmission facilities be spread throughout the entire MISO footprint.  If adopted by the FERC, this proposal would shift a greater portion of the cost of new 345 kV transmission facilities to the FirstEnergy footprint, and increase the transmission rates paid by load-serving FirstEnergy affiliates.

American Electric Power (AEP) filed a letter with the FERC Commissioners stating its intent to file a complaint under Section 206 of the Federal Power Act challenging the justness and reasonableness of the rate designs underlying the MISO and PJM transmission tariffs.  AEP will propose the adoption of a regional rate design that is expected to reallocate the cost of both existing and new high voltage transmission facilities across the combined MISO and PJM footprint.  Based upon the position advocated by AEP in a related proceeding, the AEP proposal is expected to result in a greater allocation of costs to FirstEnergy transmission zones in MISO and PJM.  If approved by the FERC, AEP’s proposal would increase the transmission rates paid by load-serving FirstEnergy affiliates.

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.

On February 15, 2007, MISO filed documents with the FERC to establish a market-based, competitive ancillary services market.  MISO contends that the filing will integrate operating reserves into MISO’s existing day-ahead and real-time settlements process, incorporate opportunity costs into these markets, address scarcity pricing through the implementation of a demand curve methodology, foster demand response in the provision of operating reserves, and provide for various efficiencies and optimization with regard to generation dispatch.  The filing also proposes amendments to existing documents to provide for the transfer of balancing functions from existing local balancing authorities to MISO.  MISO will then carry out this reliability function as the NERC-certified balancing authority for the MISO region with implementation in the third or fourth quarter of 2008.  FirstEnergy filed comments on March 23, 2007, supporting the ancillary service market in concept, but proposing certain changes in MISO’s proposal. MISO requested FERC action on its filing by June 2007 and the FERC issued its Order June 22, 2007. The FERC found MISO’s filing to be deficient in two key areas: (1) MISO has not submitted a market power analysis in support of its proposed Ancillary Services Market and (2) MISO has not submitted a readiness plan to ensure reliability during the transition from the current reserve and regulation system managed by the individual Balancing Authorities to a centralized Ancillary Services Market managed by MISO. MISO was ordered to remedy these deficiencies and the FERC provided more guidance on other issues brought up in filings by stakeholders to assist MISO to re-file a complete proposal. This Order should facilitate MISO’s timetable to incorporate final revisions to ensure a market start in Spring 2008. FirstEnergy will be participating in working groups and task forces to ensure the Spring 2008 implementation of the Ancillary Services Market.

On February 16, 2007, the FERC issued a final rule 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. As a market participant in both MISO and PJM, FirstEnergy will conform its business practices to each respective revised tariff.

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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.

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 July 25, 2007, FirstEnergy and PennFuture entered into a Tolling and Confidentiality Agreement that provides for a 60-day negotiation period during which the parties have agreed to not file a lawsuit.

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-fired generation facilities will be subject to caps on SO₂ and NO_X emissions, whereas its New Jersey fossil-fired 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.

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Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, 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.

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.

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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.

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 June 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, 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.

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The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site 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 June 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 $88 million have been accrued through June 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

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 on July 8, 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, on March 7, 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 on May 9, 2007.  Proceedings are continuing in the Superior Court.  FirstEnergy is vigorously defending this class action but is unable to predict the outcome of this matter.  No liability has been accrued as of June 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 American Electric Power Company, Inc., 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 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.

On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga County Common Pleas Court seeking reimbursement for claims paid to numerous insureds who allegedly suffered losses as a result of the August 14, 2003 outages. All of the insureds appear to be non-customers. The plaintiff insurance companies are the same claimants in one of the pending PUCO cases. FirstEnergy, the Ohio Companies and Penn were served on October 27, 2006.  On January 18, 2007, the Court granted the Companies’ motion to dismiss the case and they have not been appealed.  However, on April 25, 2007, one of the insurance carriers refiled the complaint naming only FirstEnergy as the defendant.  On July 30, 2007, the case was voluntarily dismissed.  No estimate of potential liability is available for any of these cases.

FirstEnergy was also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy were based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. None of FirstEnergy’s subsidiaries serve customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss. The plaintiff has not appealed.

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FirstEnergy is vigorously 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 August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee's failure to take prompt and corrective action. On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Nuclear Power Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections would continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.

On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance at the Perry Nuclear Power Plant and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. By two letters dated March 2, 2007, the NRC closed the CAL commitments for Perry, the two outstanding white findings, and crosscutting issues.  Moreover, the NRC removed Perry from the Multiple Degraded Cornerstone Column of the NRC Action Matrix and placed the plant in the Licensee Response Column (regular agency oversight).

On April 30, 2007, the UCS filed a petition with the NRC under Section 2.206 of the NRC’s regulations based on a report prepared at FENOC’s request by expert witnesses for an insurance arbitration.  In December 2006, the expert witnesses for FENOC completed a report that analyzed the crack growth rates in control rod drive mechanism penetrations and wastage of the former reactor pressure vessel head at Davis-Besse.   Citing the findings in the expert witness' report, the Section 2.206 petition requested that: (1) Davis-Besse be immediately shut down; (2) that the NRC conduct an independent review of the consultant's report and that all pressurized water reactors be shut down until remedial actions can be implemented; and (3) Davis-Besse’s operating license be revoked.

In a letter dated May 18, 2007, the NRC stated that the “current reactor pressure vessel (RPV) head inspection requirements are adequate to detect RPV degradation issues before they result in significant corrosion.” The NRC also indicated that, “no immediate safety concern exists at Davis-Besse” and denied UCS’ first demand (to shut down the facility).  On June 18, 2007, the NRC Petition Review Board indicated that the agency had initially denied petitioner’s other requests, and provided an opportunity for UCS to provide additional information prior to the final determination. By letter dated July 12, 2007, the NRC denied the remainder of the UCS petition.

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 the expert witnesses’ report and another report. The NRC indicated that this information is 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. FirstEnergy can provide no assurances as to the ultimate resolution of this matter.

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.

70

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 plaintiff’s motion to amend their complaint which OE has opposed.

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. JCP&L intends to re-file an appeal 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. The parties met on June 27, 2007 before an arbitrator to assert their positions regarding the finality of damages. A hearing before the arbitrator is set for September 7, 2007.

The union employees at the W. H. Sammis Plant have been working without a labor contract since July 1, 2007. The union expects to vote on a new contract on August 9, 2007. While it is expected the union will ratify a new contract, FirstEnergy has a strike mitigation plan ready in the event of a strike.

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 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.

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.

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 effect on FirstEnergy’s financial statements.

71

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
STATEMENTS OF INCOME	(In thousands)
REVENUES:
Electric sales	$	569,430		$	546,176		$	1,163,774		$	1,103,405
Excise tax collections		27,351			26,916			58,605			55,890
Total revenues		596,781			573,092			1,222,379			1,159,295
EXPENSES:
Fuel		2,312			2,821			5,327			5,772
Purchased power		322,639			293,033			672,491			576,053
Nuclear operating costs		47,654			43,506			89,168			84,590
Other operating costs		97,120			91,604			185,606			182,414
Provision for depreciation		19,110			17,547			37,958			35,563
Amortization of regulatory assets		46,126			43,444			91,543			97,305
Deferral of new regulatory assets		(54,344	)		(42,083	)		(90,993	)		(78,323	)
General taxes		45,393			43,931			95,138			89,826
Total expenses		526,010			493,803			1,086,238			993,200
OPERATING INCOME		70,771			79,289			136,141			166,095
OTHER INCOME (EXPENSE):
Investment income		21,346			32,818			47,976			65,860
Miscellaneous income (expense)		2,319			(1,001	)		2,692			(804	)
Interest expense		(21,416	)		(17,366	)		(42,438	)		(35,598	)
Capitalized interest		152			643			262			1,134
Subsidiary's preferred stock dividend requirements		-			(155	)		-			(311	)
Total other income		2,401			14,939			8,492			30,281
INCOME BEFORE INCOME TAXES		73,172			94,228			144,633			196,376
INCOME TAXES		27,559			35,019			44,985			73,337
NET INCOME		45,613			59,209			99,648			123,039
PREFERRED STOCK DIVIDEND REQUIREMENTS AND
REDEMPTION PREMIUM		-			3,587			-			4,246
EARNINGS ON COMMON STOCK	$	45,613		$	55,622		$	99,648		$	118,793
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	45,613		$	59,209		$	99,648		$	123,039
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirment benefits		(3,424	)		-			(6,847	)		-
Change in unrealized gain on available for sale securities		5,099			(4,063	)		4,973			1,672
Other comprehensive income (loss)		1,675			(4,063	)		(1,874	)		1,672
Income tax expense (benefit) related to other
comprehensive income		388			(1,466	)		(1,115	)		603
Other comprehensive income (loss), net of tax		1,287			(2,597	)		(759	)		1,069
TOTAL COMPREHENSIVE INCOME	$	46,900		$	56,612		$	98,889		$	124,108
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these
statements.

72

OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,		December 31,
	2007		2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	899	$	712
Receivables-
Customers (less accumulated provisions of $8,990,000 and $15,033,000,
respectively, for uncollectible accounts)		263,316		234,781
Associated companies		173,200		141,084
Other (less accumulated provisions of $5,090,000 and $1,985,000,
respectively, for uncollectible accounts)		13,380		13,496
Notes receivable from associated companies		367,971		458,647
Prepayments and other		20,482		13,606
		839,248		862,326
UTILITY PLANT:
In service		2,690,282		2,632,207
Less - Accumulated provision for depreciation		1,043,183		1,021,918
		1,647,099		1,610,289
Construction work in progress		37,019		42,016
		1,684,118		1,652,305
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies		639,227		1,219,325
Investment in lease obligation bonds		274,248		291,393
Nuclear plant decommissioning trusts		125,906		118,209
Other		37,970		38,160
		1,077,351		1,667,087
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		733,147		741,564
Pension assets		100,682		68,420
Property taxes		60,080		60,080
Unamortized sale and leaseback costs		47,634		50,136
Other		53,914		18,696
		995,457		938,896
	$	4,596,174	$	5,120,614
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	335,812	$	159,852
Short-term borrowings-
Associated companies		-		113,987
Other		119,943		3,097
Accounts payable-
Associated companies		120,493		115,252
Other		17,907		13,068
Accrued taxes		94,615		187,306
Accrued interest		23,406		24,712
Other		61,611		64,519
		773,787		681,793
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 175,000,000 shares -
60 and 80 shares outstanding, respectively		1,208,498		1,708,441
Accumulated other comprehensive income		2,449		3,208
Retained earnings		309,656		260,736
Total common stockholder's equity		1,520,603		1,972,385
Long-term debt and other long-term obligations		937,676		1,118,576
		2,458,279		3,090,961
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		717,373		674,288
Accumulated deferred investment tax credits		18,748		20,532
Asset retirement obligations		90,801		88,223
Retirement benefits		162,078		167,379
Deferred revenues - electric service programs		67,566		86,710
Other		307,542		310,728
		1,364,108		1,347,860
COMMITMENTS AND CONTINGENCIES (Note 9)
	$	4,596,174	$	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.

73

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30,
	2007			2006
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	99,648		$	123,039
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		37,958			35,563
Amortization of regulatory assets		91,543			97,305
Deferral of new regulatory assets		(90,993	)		(78,323	)
Amortization of lease costs		(4,367	)		(4,334	)
Deferred income taxes and investment tax credits, net		3,017			(17,351	)
Accrued compensation and retirement benefits		(25,829	)		930
Pension trust contribution		(20,261	)		-
Decrease (increase) in operating assets-
Receivables		(60,535	)		66,215
Prepayments and other current assets		(3,162	)		(7,913	)
Increase (decrease) in operating liabilities-
Accounts payable		10,080			(45,894	)
Accrued taxes		(87,969	)		9,378
Accrued interest		(1,306	)		(1,183	)
Electric service prepayment programs		(19,144	)		(16,838	)
Other		2,854			(8,051	)
Net cash provided from (used for) operating activities		(68,466	)		152,543
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			599,778
Short-term borrowings, net		2,859			-
Redemptions and Repayments-
Common stock		(500,000	)		-
Long-term debt		(1,181	)		(145,316	)
Short-term borrowings, net		-			(176,708	)
Dividend Payments-
Common stock		(50,000	)		(35,000	)
Preferred stock		-			(1,317	)
Net cash provided from (used for) financing activities		(548,322	)		241,437
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(66,607	)		(63,294	)
Sales of investment securities held in trusts		22,225			29,168
Purchases of investment securities held in trusts		(24,187	)		(29,860	)
Loan repayments from associated companies, net		670,774			112,840
Cash investments		-			78,248
Other		14,770			23,281
Net cash provided from investing activities		616,975			150,383
Net increase in cash and cash equivalents		187			544,363
Cash and cash equivalents at beginning of period		712			929
Cash and cash equivalents at end of period	$	899		$	545,292
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part
of these statements.

74

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 June 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2007 and 2006 and the consolidated statement of cash flows for the six-month periods ended June 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

August 6, 2007

75

OHIO EDISON COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND 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

Earnings on common stock in the second quarter of 2007 decreased to $46 million from $56 million in the second quarter of 2006. In the first six months of 2007, earnings on common stock decreased to $100 million from $119 million in the same period of 2006. The decrease in earnings in both periods primarily resulted from higher purchased power costs and lower other income, partially offset by higher electric sales revenues and the deferral of new regulatory assets.

Revenues

Revenues increased by $24 million or 4.1% in the second quarter of 2007 compared with the same period in 2006, primarily due to higher retail generation revenues of $15 million and wholesale generation revenues of $5 million.

Higher retail generation revenues from residential customers reflected increased sales volume and the impact of higher average unit prices. Weather conditions in the second quarter of 2007 compared to the same period in 2006 contributed to the higher KWH sales to residential customers (heating degree days increased 7.0% and 8.5% and cooling degree days increased by 74.5% and 83.8% 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 went into effect 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 the second quarter of 2007 as compared to the same period in 2006. The percentage of shopping customers increased to 27.6 percent during the second quarter of 2007 from 15.2 percent in the second quarter of 2006.

Revenues increased by $63 million or 5.4% in the first six months of 2007 compared with the same period in 2006, primarily due to higher retail generation revenues of $63 million and wholesale generation revenues of $2 million, partially offset by decreases in revenues from distribution throughput of $13 million.

Retail generation revenues increased for residential and commercial customers due to the higher prices and increased sales volume. Weather conditions in the first six months of 2007 compared to the same period in 2006 contributed to the higher KWH sales to residential and commercial customers (heating degree days increased 13.9% and 10.7% in OE’s and Penn’s service territories, respectively). Retail generation revenues from the industrial sector decreased primarily due to an increase in customer shopping in the first six months of 2007 as compared to the same period in 2006. The percentage of shopping customers increased to 26.9 percent in the first six months of 2007 from 15.9 percent in the first six months of 2006.

Changes in retail electric generation KWH sales and revenues in the second quarter and first six months of 2007 from the corresponding periods of 2006 are summarized in the following tables:

Retail Generation KWH Sales	Three Months			Six Months
Increase (Decrease)
Residential		9.0	%		10.8	%
Commercial		(1.3	)%		0.7	%
Industrial		(16.8	)%		(14.9	)%
Net Decrease in Generation Sales		(4.3	)%		(1.7	)%

Retail Generation Revenues	Three Months			Six Months
Increase (Decrease)	(In millions)
Residential	$	24		$	61
Commercial		6			22
Industrial		(15	)		(20	)
Net Increase in Generation Revenues	$	15		$	63

76

Increased revenues from distribution throughput to residential customers reflected the impact of weather conditions described above in the second quarter and first six months of 2007 as compared to the same periods in 2006, partially offset by lower composite unit prices. Reduced revenues from distribution throughput to commercial customers in the second quarter and first six months of 2007 resulted from lower unit prices, partially offset by increased KWH deliveries. Revenues from distribution throughput to industrial customers decreased in the second quarter and first six months of 2007 as a result of lower unit prices and reduced KWH deliveries.

Changes in distribution KWH deliveries and revenues in the second quarter and first six months of 2007 from the corresponding periods of 2006 are summarized in the following tables.

Changes in Distribution KWH Deliveries	Three Months			Six Months
Increase (Decrease)
Residential		7.5	%		8.7	%
Commercial		4.7	%		4.6	%
Industrial		(2.5	)%		(2.0	)%
Net Increase in Distribution Deliveries		2.7	%		3.5	%

Changes in Distribution Revenues	Three Months			Six Months
Increase (Decrease)	(In millions)
Residential	$	4		$	3
Commercial		(1	)		(5	)
Industrial		(3	)		(11	)
Changes in Distribution Revenues	$	-		$	(13	)

Expenses

Total expenses increased by $32 million in the second quarter of 2007 and $93 million in the first six months of 2007 from the same periods of 2006. The following table presents changes from the prior year by expense category.

Expenses – Changes	Three Months			Six Months
Increase (Decrease)	(In millions)
Purchased power costs	$	30		$	97
Nuclear operating costs		4			4
Other operating costs		5			3
Provision for depreciation		1			2
Amortization of regulatory assets		3			(5	)
Deferral of new regulatory assets		(12	)		(13	)
General taxes		1			5
Net Increase in Expenses	$	32		$	93

Higher purchased power costs in the second quarter and first six months of 2007 primarily reflected higher unit prices under Penn’s competitive RFP process and OE’s PSA with FES. The increase in nuclear operating costs during the second quarter and first six months of 2007 was due to expenses related to the second quarter 2007 nuclear refueling outage at the Perry Plant. The increase in other operating costs during the second quarter of 2007 was primarily due to higher transmission expenses related to MISO operations, partially offset by lower employee benefit expenses. Lower amortization of regulatory assets for the first six months of 2007 was due to the completion of the generation-related transition cost amortization under OE’s and Penn’s respective transition plans at the end of January 2006. The decreases in expense related to the deferral of new regulatory assets for the second quarter of 2007 and first six months of 2007 were primarily due to increases in MISO cost deferrals and related interest. General taxes were higher in the first six 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 $13 million in the second quarter of 2007 and $22 million in the first six months of 2007 as compared with the same periods of 2006, primarily due to reductions in interest income on notes receivable resulting from principal payments from associated companies. Higher interest expense in the second quarter and first six months of 2007 also contributed to the decrease in other income in both periods of 2007 and was largely due to OE’s issuance of $600 million of long-term debt in June 2006, partially offset by debt redemptions that have occurred since the second quarter of 2006.

77

Income Taxes

In the first six months of 2007, OE’s income taxes included a $7.2 million adjustment related to an inter-company federal tax allocation arrangement between FirstEnergy and its subsidiaries.

Capital Resources and Liquidity

During 2007, OE expects to meet its contractual obligations primarily with cash from operations and short-term credit arrangements. Borrowing capacity under OE’s credit facilities is available to manage its working capital requirements.

Changes in Cash Position

OE had $899,000 of cash and cash equivalents as of June 30, 2007 compared with $712,000 as of December 31, 2006. The major sources for changes in these balances are summarized below.

Cash Flows From Operating Activities

Net cash provided from operating activities in the first six months of 2007 and 2006 were as follows:

	Six Months Ended June 30,
Operating Cash Flows	2007			2006
	(In millions)
Net income	$	100		$	123
Non-cash charges (credits)		(7	)		18
Pension trust contribution		(20	)		-
Working capital and other		(141	)		12
Net cash provided from (used for) operating activities	$	(68	)	$	153

The changes in net income and non-cash charges are described above under “Results of Operations.” The decrease from working capital changes primarily reflects changes in accounts receivable of $127 million and accrued taxes of $97 million, partially offset by changes in accounts payable of $56 million.

Cash Flows From Financing Activities

In the first six months of 2007, net cash used for financing activities was $548 million compared to $241 million provided from financing activities in the same period last year. This change primarily resulted from a $500 million repurchase of common stock from FirstEnergy, a $276 million net decrease in new financing activity and a $15 million increase in common stock dividends to FirstEnergy.

OE had approximately $369 million of cash and temporary cash investments (which include short-term notes receivable from associated companies) and $120 million of short-term indebtedness as of June 30, 2007. OE has authorization from the PUCO to incur short-term debt of up to $500 million through bank facilities and the utility money pool. Penn has authorization from the FERC to incur short-term debt up to its charter limit of $39 million as of June 30, 2007, and also has access to bank facilities and the utility money pool.

In February 2007, FES made a $562 million payment on its fossil generation asset transfer notes owed to OE and Penn. OE used $500 million of the proceeds to repurchase shares of its common stock from FirstEnergy.

See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of OE’s financing capabilities.

Cash Flows From Investing Activities

Net cash provided from investing activities increased $467 million in the first six months of 2007 from the same period in 2006. The increase resulted primarily from a $558 million increase in loan repayments from associated companies (including the $562 million payment from FES described above), partially offset by a $78 million change in cash investments.

78

During the second half of 2007, OE’s capital spending is expected to be approximately $70 million. OE has additional requirements of approximately $3 million for maturing long-term debt during that period. These cash requirements are expected to be satisfied from a combination of cash from operations and short-term credit arrangements. OE’s capital spending for the period 2007-2011 is expected to be about $769 million, of which approximately $139 million applies to 2007.

Off-Balance Sheet Arrangements

Obligations not included on OE’s Consolidated Balance Sheets primarily consist of sale and leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2. As of June 30, 2007, the present value of these operating lease commitments, net of trust investments, was $619 million.

Equity Price Risk

Included in OE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $82 million and $80 million as of June 30, 2007 and December 31, 2006, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $8 million reduction in fair value as of June 30, 2007.

Regulatory Matters

See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to OE.

Environmental Matters

See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to OE.

Other Legal Proceedings

See the “Other Legal Proceedings” section 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.

.

79

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
	(In thousands)
REVENUES:
Electric sales	$	433,014		$	416,690		$	855,819		$	807,189
Excise tax collections		16,468			15,681			34,495			32,992
Total revenues		449,482			432,371			890,314			840,181
EXPENSES:
Fuel		14,332			13,413			27,523			26,976
Purchased power		178,669			157,941			359,326			301,711
Other operating costs		83,075			68,436			158,026			141,331
Provision for depreciation		18,713			11,050			37,181			28,251
Amortization of regulatory assets		35,047			29,476			68,176			61,006
Deferral of new regulatory assets		(43,059	)		(31,697	)		(77,016	)		(62,223	)
General taxes		34,098			31,510			72,992			66,580
Total expenses		320,875			280,129			646,208			563,632
OPERATING INCOME		128,607			152,242			244,106			276,549
OTHER INCOME (EXPENSE):
Investment income		16,324			24,674			34,011			51,610
Miscellaneous income		3,226			5,642			3,957			5,396
Interest expense		(37,267	)		(34,634	)		(73,007	)		(69,366	)
Capitalized interest		141			837			346			1,510
Total other expense		(17,576	)		(3,481	)		(34,693	)		(10,850	)
INCOME BEFORE INCOME TAXES		111,031			148,761			209,413			265,699
INCOME TAXES		42,082			57,709			76,915			102,234
NET INCOME		68,949			91,052			132,498			163,465
OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits		1,203			-			2,405			-
Income tax expense related to other comprehensive income		357			-			712			-
Other comprehensive income, net of tax		846			-			1,693			-
TOTAL COMPREHENSIVE INCOME	$	69,795		$	91,052		$	134,191		$	163,465
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an
integral part of these statements.

80

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,			December 31,
	2007			2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	236		$	221
Receivables-
Customers (less accumulated provisions of $8,554,000 and $6,783,000
respectively, for uncollectible accounts)		290,711			245,193
Associated companies		59,852			249,735
Other		12,775			14,240
Notes receivable from associated companies		24,898			27,191
Prepayments and other		2,002			2,314
		390,474			538,894
UTILITY PLANT:
In service		2,183,308			2,136,766
Less - Accumulated provision for depreciation		839,003			819,633
		1,344,305			1,317,133
Construction work in progress		46,543			46,385
		1,390,848			1,363,518
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies		353,293			486,634
Investment in lessor notes		463,436			519,611
Other		10,316			13,426
		827,045			1,019,671
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		1,688,521			1,688,521
Regulatory assets		862,758			854,588
Pension assets		15,124			-
Property taxes		65,000			65,000
Other		51,028			33,306
		2,682,431			2,641,415
	$	5,290,798		$	5,563,498
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	120,597		$	120,569
Short-term borrowings-
Associated companies		179,892			218,134
Accounts payable-
Associated companies		71,407			365,678
Other		6,517			7,194
Accrued taxes		88,277			128,829
Accrued interest		22,150			19,033
Lease market valuation liability		58,750			60,200
Other		37,473			52,101
		585,063			971,738
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 105,000,000 shares -
67,930,743 shares outstanding		860,206			860,133
Accumulated other comprehensive loss		(102,738	)		(104,431	)
Retained earnings		741,439			713,201
Total common stockholder's equity		1,498,907			1,468,903
Long-term debt and other long-term obligations		1,936,862			1,805,871
		3,435,769			3,274,774
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		492,203			470,707
Accumulated deferred investment tax credits		19,422			20,277
Lease market valuation liability		505,725			547,800
Retirement benefits		110,329			122,862
Deferred revenues - electric service programs		40,459			51,588
Other		101,828			103,752
		1,269,966			1,316,986
COMMITMENTS AND CONTINGENCIES (Note 9)
	$	5,290,798		$	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.

81

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30,
	2007			2006
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	132,498		$	163,465
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		37,181			28,251
Amortization of regulatory assets		68,176			61,006
Deferral of new regulatory assets		(77,016	)		(62,223	)
Nuclear fuel and capital lease amortization		116			120
Deferred rents and lease market valuation liability		(45,858	)		(55,043	)
Deferred income taxes and investment tax credits, net		(7,103	)		(4,745	)
Accrued compensation and retirement benefits		1,594			1,584
Pension trust contribution		(24,800	)		-
Decrease (increase) in operating assets-
Receivables		156,526			46,262
Prepayments and other current assets		163			399
Increase (decrease) in operating liabilities-
Accounts payable		(308,551	)		(6,388	)
Accrued taxes		(40,119	)		(1,932	)
Accrued interest		3,117			(76	)
Electric service prepayment programs		(11,129	)		(7,695	)
Other		573			(4,162	)
Net cash provided from (used for) operating activities		(114,632	)		158,823
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		247,426			-
Redemptions and Repayments-
Long-term debt		(103,397	)		(118,152	)
Short-term borrowings, net		(52,894	)		(57,675	)
Dividend Payments-
Common stock		(104,000	)		(63,000	)
Net cash used for financing activities		(12,865	)		(238,827	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(64,366	)		(65,551	)
Loan repayments from associated companies, net		2,292			108,169
Collection of principal on long-term notes receivable		133,341			-
Redemption of lessor notes		56,175			44,551
Other		70			(7,155	)
Net cash provided from investing activities		127,512			80,014
Net increase in cash and cash equivalents		15			10
Cash and cash equivalents at beginning of period		221			207
Cash and cash equivalents at end of period	$	236		$	217
The preceeding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company
are an integral part of these statements.

82

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 June 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2007 and 2006 and the consolidated statement of cash flows for the six-month periods ended June 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

August 6, 2007

83

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND 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 second quarter of 2007 decreased to $69 million from $91 million in the same period of 2006.  In the first six months of 2007, net income decreased to $132 million from $163 million in the same period of 2006. The decrease in both periods resulted primarily from higher purchased power costs and other operating costs, partially offset by higher revenues and the deferral of new regulatory assets.

Revenues

Revenues increased by $17 million or 4% in the second quarter of 2007 from the same period of 2006 primarily due to higher retail generation and distribution revenues. Retail generation revenues increased $11 million due to increased KWH sales in the residential and commercial sectors and higher composite unit prices in the commercial and industrial sectors. More extreme weather in the second quarter of 2007 compared to the unseasonably mild weather in the same period in 2006 contributed to the higher KWH sales for both residential and commercial customers (cooling degree days increased 82% and heating degree days were 10% higher in 2007).

In the first six months of 2007, revenues increased by $50 million or 6% compared to the same period of 2006 primarily due to higher retail generation and wholesale revenues.  Retail generation revenues increased by $33 million due to increased KWH sales and higher composite unit prices in all classes.  The weather contributed to the increased KWH sales in the residential and commercial sectors (cooling degree days increased 84% and heating degree days increased 16% from the same period in 2006).  Increased industrial KWH sales reflected a slight decrease in customer shopping.

Wholesale generation revenues increased by $1 million in the second quarter and $12 million in the first six months of 2007 compared to the corresponding periods of 2006.  The increases in both periods were primarily due to higher unit prices for PSA sales to associated companies.  In the first six months of 2007 higher unit prices were partially offset by a decrease in sales volume due in part to maintenance outages at the Bruce Mansfield Plant in the first quarter of 2007. CEI sells KWH from its leasehold interests in the Bruce Mansfield Plant to FGCO.

Increases in retail electric generation sales and revenues in the second quarter and the first six months of 2007 compared to the corresponding periods of 2006 are summarized in the following tables:

Retail Generation KWH Sales	Three Months			Six Months
Residential		5.3	%		6.8	%
Commercial		6.6	%		6.9	%
Industrial		0.8	%		2.0	%
Increase in Retail Generation Sales		3.3	%		4.5	%

Retail Generation Revenues	Three Months		Six Months
	(In millions)
Residential	$	2	$	9
Commercial		5		12
Industrial		4		12
Increase in Generation Revenues	$	11	$	33

Revenues from distribution throughput increased by $3 million in the second quarter and $1 million in the first six months of 2007 compared to the same periods of 2006 primarily due to increased residential and commercial KWH deliveries, offset by lower composite unit prices in all classes. Increased KWH deliveries were primarily a result of the more extreme weather in 2007 as described above.

84

Changes in distribution KWH deliveries and revenues in the second quarter and first six months of 2007 compared to the corresponding periods of 2006 are summarized in the following tables.

Increase in Distribution KWH Deliveries	Three Months			Six Months
Residential		5.4	%		6.9	%
Commercial		4.6	%		4.8	%
Industrial		0.9	%		1.5	%
Total Increase in Distribution Deliveries		3.0	%		3.8	%

Change in Distribution Revenues	Three Months			Six Months
Increase (Decrease)	(In millions)
Residential	$	3		$	5
Commercial		2			3
Industrial		(2	)		(7	)
Net Increase in Distribution Revenues	$	3		$	1

Expenses

Total expenses increased by $41 million in the second quarter and $83 million in the first six months of 2007 compared to the corresponding periods of 2006. The following table presents changes in each period from the prior year by expense category:

Expenses  - Changes	Three Months			Six Months
Increase (Decrease)	(In millions)
Fuel costs	$	1		$	1
Purchased power costs		21			58
Other operating costs		15			17
Provision for depreciation		8			9
Amortization of regulatory assets		5			7
Deferral of new regulatory assets		(11	)		(15	)
General taxes		2			6
Net Increase in Expenses	$	41		$	83

Higher purchased power costs in the second quarter and the first six months of 2007 compared to the corresponding periods of 2006 primarily reflect higher unit prices associated with the PSA with FES and an increase in KWH purchases to meet CEI’s higher retail generation sales requirements. The higher other operating costs in the second quarter and the first six months of 2007 compared to the same periods of 2006 reflect an increase in MISO transmission related expenses. The difference between transmission revenues accrued and transmission costs incurred is deferred, resulting in no material impact to current period earnings. The increased depreciation in the second quarter of 2007 and the first six months of 2007 is primarily due to the absence of credit adjustments in the second quarter of 2006 related to prior periods ($6.5 million pre-tax, $4 million net of tax).

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

Other Expense

Other expense increased by $14 million in the second quarter and $24 million in the first six months of 2007 compared to the corresponding periods 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 second quarter of 2006 on notes receivable related to the generation asset transfers. In addition, there was a $6 million benefit recognized in the second quarter of 2006 related to the sale of the Ashtabula C.

Capital Resources and Liquidity

During 2007, CEI expects to meet its contractual obligations with cash from operations and short-term credit arrangements.

85

Changes in Cash Position

As of June 30, 2007, CEI had $236,000 of cash and cash equivalents, compared with $221,000 as of December 31, 2006. The major sources of changes in these balances are summarized below.

Cash Flows from Operating Activities

Cash used for operating activities during the first six months of 2007, compared with cash provided from operating activities for the first six months of 2006, were as follows:

	Six Months Ended June 30,
Operating Cash Flows	2007			2006
	(In millions)
Net Income	$	132		$	163
Non-cash credits		(34	)		(38	)
Pension trust contribution		(25	)		-
Working capital and other		(188	)		34
Net cash provided from (used for) operating activities	$	(115	)	$	159

Net cash used for operating activities was $115 million in the first six months of 2007 compared to $159 million provided from operating activities for the same period in 2006.  The $274 million change was primarily due to a $25 million pension trust contribution in the first quarter of 2007 and a $222 million change in working capital and other. The change in working capital was due to changes in accounts payable of $302 million (primarily for the settlement of payables with associated companies) and accrued taxes of $38 million, partially offset by changes in accounts receivable of $110 million. The changes in net income and non–cash credits are described above under “Results of Operations.”

Cash Flows from Financing Activities

Net cash used for financing activities was $13 million in the first six months of 2007 compared to $239 million in the same period of 2006. The change reflects $248 million of new long-term debt financing and a $14 million decrease in repayments of long-term debt, partially offset by a $41 million increase in common stock dividend payments to FirstEnergy.

CEI had $25 million of cash and temporary investments (which included short-term notes receivable from associated companies) and approximately $180 million of short-term indebtedness as of June 30, 2007. CEI has obtained authorization from the PUCO to incur short-term debt of up to $500 million through bank facilities and the utility money pool.

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 short-term borrowings and for general corporate purposes. On June 1, 2007 CEI redeemed $103 million of Trust C preferred securities.

See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of CEI’s financing capabilities.

Cash Flows from Investing Activities

Net cash provided from investing activities increased by $47 million in the first six months of 2007 compared to the same period of 2006. The change was primarily due to the collection of principal on long-term notes receivable, partially offset by a decrease in loan repayments from associated companies.

CEI’s capital spending for the last two quarters of 2007 is expected to be about $92 million. These cash requirements are expected to be satisfied with cash from operations and short-term credit arrangements. CEI’s capital spending for the period 2007-2011 is expected to be about $843 million, of which approximately $160 million applies to 2007.

86

Off-Balance Sheet Arrangements

Obligations not included on CEI’s Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant. As of June 30, 2007, the present value of these operating lease commitments, net of trust investments, total $82 million.

Regulatory Matters

See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to CEI.

Environmental Matters

See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to CEI.

Other Legal Proceedings

See the “Other Legal Proceedings” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other 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.

87

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
STATEMENTS OF INCOME	(In thousands)
REVENUES:
Electric sales	$	233,637		$	219,139		$	466,693		$	430,013
Excise tax collections		6,700			6,459			14,100			13,562
Total revenues		240,337			225,598			480,793			443,575
EXPENSES:
Fuel		10,461			9,638			20,608			19,400
Purchased power		96,276			80,659			192,445			156,079
Nuclear operating costs		17,846			17,866			35,567			35,198
Other operating costs		46,164			39,718			89,085			80,143
Provision for depreciation		9,127			8,240			18,244			16,337
Amortization of regulatory assets		24,948			22,117			48,824			46,573
Deferral of new regulatory assets		(18,247	)		(14,190	)		(31,728	)		(27,846	)
General taxes		13,000			12,253			26,734			25,184
Total expenses		199,575			176,301			399,779			351,068
OPERATING INCOME		40,762			49,297			81,014			92,507
OTHER INCOME (EXPENSE):
Investment income		7,309			8,945			14,534			18,725
Miscellaneous expense		(2,056	)		(1,926	)		(5,156	)		(4,610	)
Interest expense		(8,916	)		(4,364	)		(16,419	)		(8,674	)
Capitalized interest		164			344			247			558
Total other income (expense)		(3,499	)		2,999			(6,794	)		5,999
INCOME BEFORE INCOME TAXES		37,263			52,296			74,220			98,506
INCOME TAXES		15,392			19,924			26,489			37,128
NET INCOME		21,871			32,372			47,731			61,378
PREFERRED STOCK DIVIDEND REQUIREMENTS		-			1,161			-			2,436
EARNINGS ON COMMON STOCK	$	21,871		$	31,211		$	47,731		$	58,942
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	21,871		$	32,372		$	47,731		$	61,378
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		573			-			1,146			-
Change in unrealized gain on available for sale securities		(669	)		191			(290	)		(947	)
Other comprehensive income (loss)		(96	)		191			856			(947	)
Income tax expense (benefit) related to other
comprehensive income		(43	)		69			291			(342	)
Other comprehensive income (loss), net of tax		(53	)		122			565			(605	)
TOTAL COMPREHENSIVE INCOME	$	21,818		$	32,494		$	48,296		$	60,773
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of
these statements.

88

THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,			December 31,
	2007			2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	22		$	22
Receivables-
Customers		1,081			772
Associated companies		37,927			13,940
Other (less accumulated provisions of $408,000 and $430,000,
respectively, for uncollectible accounts)		4,334			3,831
Notes receivable from associated companies		120,101			100,545
Prepayments and other		792			851
		164,257			119,961
UTILITY PLANT:
In service		907,710			894,888
Less - Accumulated provision for depreciation		403,634			394,225
		504,076			500,663
Construction work in progress		14,573			16,479
		518,649			517,142
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes		154,647			169,493
Long-term notes receivable from associated companies		96,521			128,858
Nuclear plant decommissioning trusts		62,289			61,094
Other		1,808			1,871
		315,265			361,316
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		500,576			500,576
Regulatory assets		230,002			247,595
Pension assets		5,379			-
Property taxes		22,010			22,010
Other		45,194			30,042
		803,161			800,223
	$	1,801,332		$	1,798,642
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	30,000		$	30,000
Accounts payable-
Associated companies		36,974			84,884
Other		4,020			4,021
Notes payable to associated companies		242,253			153,567
Accrued taxes		46,153			47,318
Lease market valuation liability		23,655			24,600
Other		18,755			37,551
		401,810			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		166,801			166,786
Accumulated other comprehensive loss		(36,239	)		(36,804	)
Retained earnings		212,071			204,423
Total common stockholder's equity		489,643			481,415
Long-term debt		358,227			358,281
		847,870			839,696
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		160,799			161,024
Accumulated deferred investment tax credits		10,597			11,014
Lease market valuation liability		198,688			218,800
Retirement benefits		76,270			77,843
Asset retirement obligations		27,439			26,543
Deferred revenues - electric service programs		18,212			23,546
Other		59,647			58,235
		551,652			577,005
COMMITMENTS AND CONTINGENCIES (Note 9)
	$	1,801,332		$	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.

89

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30,
	2007			2006
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	47,731		$	61,378
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		18,244			16,337
Amortization of regulatory assets		48,824			46,573
Deferral of new regulatory assets		(31,728	)		(27,846	)
Deferred rents and lease market valuation liability		(41,981	)		(45,843	)
Deferred income taxes and investment tax credits, net		(11,924	)		(13,322	)
Accrued compensation and retirement benefits		1,277			1,268
Pension trust contribution		(7,659	)		-
Decrease (increase) in operating assets-
Receivables		(21,594	)		(18,257	)
Prepayments and other current assets		59			(4,076	)
Increase (decrease) in operating liabilities-
Accounts payable		(56,784	)		(14,231	)
Accrued taxes		751			3,748
Accrued interest		1			(222	)
Electric service prepayment programs		(5,334	)		(4,454	)
Other		1,093			3,326
Net cash provided from (used for) operating activities		(59,024	)		4,379
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		88,686			71,882
Redemptions and Repayments-
Preferred stock		-			(30,000	)
Long-term debt		-			(53,650	)
Dividend Payments-
Common stock		(40,000	)		(25,000	)
Preferred stock		-			(2,436	)
Net cash provided from (used for) financing activities		48,686			(39,204	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(19,804	)		(29,361	)
Loan repayments from (loans to) associated companies, net		(19,546	)		2,611
Collection of principal on long-term notes receivable		32,327			53,766
Redemption of lessor notes		14,846			9,305
Sales of investment securities held in trusts		32,499			30,954
Purchases of investment securities held in trusts		(32,796	)		(31,043	)
Other		2,812			(1,399	)
Net cash provided from investing activities		10,338			34,833
Net change in cash and cash equivalents		-			8
Cash and cash equivalents at beginning of period		22			15
Cash and cash equivalents at end of period	$	22		$	23
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo 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 The Toledo Edison Company:

We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of June 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2007 and 2006 and the consolidated statement of cash flows for the six-month periods ended June 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

August 6, 2007

91

THE TOLEDO EDISON COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND 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 second quarter of 2007 decreased to $22 million from $31 million in the second quarter of 2006. Earnings on common stock in the first six months of 2007 decreased to $48 million from $59 million in the same period of 2006. The decreases in both periods resulted primarily from higher purchased power and other operating costs, partially offset by higher electric sales revenues and the deferral of new regulatory assets.

Revenues

Revenues increased $15 million or 6.5% in the second quarter of 2007 compared to the same period of 2006 primarily due to higher retail and wholesale generation revenues. Retail generation revenues increased by $8 million in the second quarter of 2007 due to higher average prices and increased sales volume across all customer classes. Average prices increased primarily due to higher composite unit prices for retail generation shopping customers returning to TE. Generation services provided by alternative suppliers as a percentage of total sales delivered in TE’s franchise area decreased by 1 percentage point for residential customers from the second quarter of 2006.  The increase in sales volume also resulted from changes in weather in the second quarter of 2007 (heating and cooling degree days increased 14.3% and 38.4%, respectively, from the second quarter of 2006).

The increase in wholesale revenues ($2 million) resulted primarily from increased KWH sales to associated companies, partially offset by lower unit prices. TE sells KWH from its leasehold interests in Beaver Valley Unit 2 and the Bruce Mansfield Plant to CEI and FGCO, respectively.

Revenues increased $37 million or 8.4% in the first six months of 2007 compared to the same period of 2006 primarily due to higher retail generation revenues of $20 million, higher wholesale generation revenues of $12 million and higher transmission revenues from non-associated companies of $2 million. Retail generation revenues increased for all customer sectors in the first six months of 2007 due to higher average prices and increased sales volume as 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. Generation services provided by alternative suppliers as a percentage of total sales delivered in TE’s franchise area decreased by 3 percentage points and 1 percentage point for residential and commercial customers, respectively.  The increase in sales volume also reflects weather impacts in the first six months of 2007 (heating and cooling degree days increased 16.9% and 39.3%, 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.  Wholesale revenues from non-associated companies decreased $2 million primarily due to lower sales to municipal customers.

Increases in electric generation KWH sales and revenues in the second quarter and first six months of 2007 from the corresponding periods of 2006 are summarized in the following tables.

Increase in Retail Generation KWH Sales	Three Months			Six Months
Residential		9.7	%		11.9	%
Commercial		3.7	%		4.5	%
Industrial		0.4	%		0.6	%
Total Retail Electric Generation Sales		2.9	%		3.9	%

Increase in Retail Generation Revenues	Three Months		Six Months
	(In millions)
Residential	$	2	$	7
Commercial		2		4
Industrial		4		9
Total Retail Generation Revenues	$	8	$	20

92

Revenues from distribution throughput increased by $4 million and $2 million in the second quarter and first six months of 2007, respectively, compared to the respective periods in 2006 due to higher KWH deliveries to all customer sectors, partially offset by lower composite unit prices. The higher KWH deliveries to residential and commercial customers in both the second quarter and first six months of 2007 reflected the impact of weather variations described above in both periods of 2007 compared to the respective periods in 2006.

Changes in distribution KWH deliveries and revenues in the second quarter and first six months of 2007 from the corresponding periods of 2006 are summarized in the following tables.

Increase in Distribution KWH Deliveries	Three Months			Six Months
Residential		8.6	%		8.2	%
Commercial		4.3	%		3.5	%
Industrial		0.7	%		0.6	%
Total Increase in Distribution Deliveries		3.2	%		3.1	%

Changes in Distribution Revenues	Three Months		Six Months
Increase (Decrease)	(In millions)
Residential	$	2	$	4
Commercial		2		2
Industrial		-		(4	)
Net Increase in Distribution Revenues	$	4	$	2

Expenses

Total expenses increased by $23 million and $49 million in the second quarter and the first six months of 2007, respectively, from the same periods of 2006. The following table presents changes from the prior year by expense category:

Expenses – Changes	Three Months			Six Months
Increase (Decrease)	(In millions)
Fuel	$	1		$	1
Purchased power costs		15			36
Other operating costs		6			9
Provision for depreciation		1			2
Amortization of regulatory assets		3			2
Deferral of new regulatory assets		(4	)		(3	)
General taxes		1			2
Net increase in expenses	$	23		$	49

Higher purchased power costs in the second quarter of 2007 compared to the second quarter 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 a $7 million increase in MISO network transmission expense assessments in the second quarter of 2007. Higher amortization of regulatory assets reflected increased amortization of transition cost deferrals and MISO transmission deferrals. The change in the deferral of new regulatory assets was primarily due to $5 million of increased deferrals for MISO transmission expenses.  The difference between transmission revenues accrued and transmission costs incurred is deferred, resulting in no material impact to current period earnings.

Higher purchased power costs in the first six 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. Higher amortization of regulatory assets reflected increased amortization of transition cost deferrals and MISO transmission deferrals.  The change in the deferral of new regulatory assets was primarily due to increased deferrals for MISO transmission expenses and RCP reliability costs, partially offset by lower RCP fuel cost deferrals. Other operating costs were higher due to an $8 million increase in MISO network transmission expenses in the first six months of 2007. Depreciation expense was higher due to an increase in depreciable property as a result of plant additions. Higher general taxes primarily reflected increased property taxes and higher KWH excise taxes.

93

Other Expense

Other expense increased $6 million in the second quarter of 2007 and $13 million in the first six months of 2007 compared to the same periods 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 second 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.

Capital Resources and Liquidity

During 2007, TE expects to meet its contractual obligations primarily with cash from operations and short-term credit arrangements. Borrowing capacity under TE’s credit facilities is available to manage its working capital requirements.

Changes in Cash Position

There was no change as of June 30, 2007 from December 31, 2006 in TE’s cash and cash equivalents of $22,000.

Cash Flows From Operating Activities

Net cash provided from (used for) operating activities in the first six months of 2007 and 2006 were as follows:

	Six  Months Ended June 30,
Operating Cash Flows	2007			2006
	(In millions)
Net income	$	48		$	61
Non-cash credits		(22	)		(27	)
Pension trust contribution		(8	)		-
Working capital and other		(77	)		(30	)
Net cash provided from (used for) operating activities	$	(59	)	$	4

Net cash used for operating activities was $59 million in the first six months of 2007 compared to net cash provided from operating activities of $4 million in the same period of 2006. The change was the result of a $13 million decrease in net income, an $8 million pension trust contribution in the first six months of 2007 and a $47 million decrease from changes in working capital and other, partially offset by a $5 million decrease in net non-cash credits. The change in net income is described above under “Results of Operations.”  The changes in working capital and other are primarily due to increased cash outflows for accounts payable of $43 million.

Cash Flows From Financing Activities

Net cash provided from financing activities increased by $88 million in the first six months of 2007 compared to the same period of 2006. The increase resulted primarily from a $17 million increase in short-term borrowings, a $30 million decrease in preferred stock redemptions and a $54 million decrease in long-term debt redemptions, partially offset by a $15 million increase in common stock dividends to FirstEnergy in the first six months of 2007.

TE had $120 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $242 million of short-term indebtedness as of June 30, 2007. TE has authorization from the PUCO to incur short-term debt of up to $500 million through bank facilities and the utility money pool.

See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of TE’s financing capabilities.

Cash Flows From Investing Activities

Net cash provided from investing activities decreased by $24 million in the first six months of 2007 compared to the same period of 2006. The change was primarily due to a $44 million net decrease in loan repayments from associated companies, partially offset by a $10 million decrease in property additions and a $6 million increase from the redemption of lessor notes.

94

TE’s capital spending for the last two quarters of 2007 is expected to be about $38 million. TE has additional requirements of $30 million for maturing long-term debt during the remainder of 2007. These cash requirements are expected to be satisfied primarily with cash from operations and short-term credit arrangements. TE’s capital spending for the period 2007-2011 is expected to be nearly $322 million, of which approximately $61 million applies to 2007.

Off-Balance Sheet Arrangements

Obligations not included on TE’s Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley Unit 2. As of June 30, 2007, the present value of these operating lease commitments, net of trust investments, total $442 million.

Regulatory Matters

See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to TE.

Environmental Matters

See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to TE.

Other Legal Proceedings

See the “Other Legal Proceedings” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other 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.

95

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
STATEMENTS OF INCOME	(In thousands)
REVENUES:
Electric sales	$	768,190		$	600,560		$	1,439,097		$	1,164,110
Excise tax collections		11,845			10,924			24,681			23,166
Total revenues		780,035			611,484			1,463,778			1,187,276
EXPENSES:
Purchased power		464,505			343,045			851,002			658,755
Other operating costs		74,564			72,105			149,215			155,133
Provision for depreciation		21,319			20,826			41,835			41,454
Amortization of regulatory assets		93,890			65,526			189,118			132,271
General taxes		15,553			14,272			32,552			30,504
Total expenses		669,831			515,774			1,263,722			1,018,117
OPERATING INCOME		110,204			95,710			200,056			169,159
OTHER INCOME (EXPENSE):
Miscellaneous income		3,238			2,528			6,299			6,071
Interest expense		(24,494	)		(20,367	)		(46,910	)		(40,983	)
Capitalized interest		563			1,037			1,076			1,929
Total other expense		(20,693	)		(16,802	)		(39,535	)		(32,983	)
INCOME BEFORE INCOME TAXES		89,511			78,908			160,521			136,176
INCOME TAXES		39,698			38,632			72,362			62,190
NET INCOME		49,813			40,276			88,159			73,986
PREFERRED STOCK DIVIDEND REQUIREMENTS		-			125			-			250
EARNINGS ON COMMON STOCK	$	49,813		$	40,151		$	88,159		$	73,736
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	49,813		$	40,276		$	88,159		$	73,986
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(2,115	)		-			(4,230	)		-
Unrealized gain on derivative hedges		69			38			166			107
Other comprehensive income (loss)		(2,046	)		38			(4,064	)		107
Income tax expense (benefit) related to other
comprehensive income		(995	)		15			(1,979	)		43
Other comprehensive income (loss), net of tax		(1,051	)		23			(2,085	)		64
TOTAL COMPREHENSIVE INCOME	$	48,762		$	40,299		$	86,074		$	74,050
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral
part of these statements.

96

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,			December 31,
	2007			2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	87		$	41
Receivables-
Customers (less accumulated provisions of $4,042,000 and $3,524,000,
respectively, for uncollectible accounts)		378,940			254,046
Associated companies		186			11,574
Other (less accumulated provisions of $701,000 and $204,000,
respectively, for uncollectible accounts)		64,010			40,023
Notes receivable - associated companies		23,691			24,456
Materials and supplies, at average cost		1,953			2,043
Prepaid taxes		122,391			13,333
Other		10,480			18,076
		601,738			363,592
UTILITY PLANT:
In service		4,074,918			4,029,070
Less - Accumulated provision for depreciation		1,484,602			1,473,159
		2,590,316			2,555,911
Construction work in progress		97,539			78,728
		2,687,855			2,634,639
OTHER PROPERTY AND INVESTMENTS:
Nuclear fuel disposal trust		170,840			171,045
Nuclear plant decommissioning trusts		172,371			164,108
Other		2,065			2,047
		345,276			337,200
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		1,824,873			2,152,332
Goodwill		1,962,361			1,962,361
Pension Assets		39,609			14,660
Other		15,724			17,781
		3,842,567			4,147,134
	$	7,477,436		$	7,482,565
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	39,082		$	32,683
Short-term borrowings-
Associated companies		263,809			186,540
Accounts payable-
Associated companies		7,325			80,426
Other		229,023			160,359
Accrued taxes		18,600			1,451
Accrued interest		10,621			14,458
Cash collateral from suppliers		8,505			32,300
Other		83,766			96,150
		660,731			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		2,789,235			2,908,279
Accumulated other comprehensive loss		(46,339	)		(44,254	)
Retained earnings		218,545			145,480
Total common stockholder's equity		3,105,657			3,159,598
Long-term debt and other long-term obligations		1,575,430			1,320,341
		4,681,087			4,479,939
NONCURRENT LIABILITIES:
Power purchase contract loss liability		877,297			1,182,108
Accumulated deferred income taxes		780,004			803,944
Nuclear fuel disposal costs		188,205			183,533
Asset retirement obligations		87,018			84,446
Other		203,094			144,228
		2,135,618			2,398,259
COMMITMENTS AND CONTINGENCIES (Note 9)
	$	7,477,436		$	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.

97

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30,
	2007			2006
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	88,159		$	73,986
Adjustments to reconcile net income to net cash from operating activities -
Provision for depreciation		41,835			41,454
Amortization of regulatory assets		189,118			132,271
Deferred purchased power and other costs		(111,517	)		(134,759	)
Deferred income taxes and investment tax credits, net		(3,116	)		10,942
Accrued compensation and retirement benefits		(11,467	)		(3,436	)
Cash collateral returned to suppliers		(23,905	)		(108,791	)
Pension trust contribution		(17,800	)		-
Decrease (increase) in operating assets-
Receivables		(137,492	)		(24,074	)
Materials and supplies		90			91
Prepaid taxes		(109,058	)		(100,650	)
Other current assets		2,540			1,718
Increase (decrease) in operating liabilities-
Accounts payable		(4,438	)		23,589
Accrued taxes		27,515			(9,062	)
Accrued interest		(3,837	)		362
Tax collections payable		(12,478	)		(10,322	)
Other		(6,114	)		8,680
Net cash used for operating activities		(91,965	)		(98,001	)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		550,000			200,003
Short-term borrowings, net		77,269			183,818
Redemptions and Repayments-
Long-term debt		(304,579	)		(157,659	)
Common Stock		(125,000	)		-
Dividend Payments-
Common stock		(15,000	)		(25,000	)
Preferred stock		-			(250	)
Net cash provided from financing activities		182,690			200,912
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(95,310	)		(91,101	)
Loan repayments from (loans to) associated companies, net		765			(9,347	)
Sales of investment securities held in trusts		77,941			131,079
Purchases of investment securities held in trusts		(79,388	)		(132,526	)
Other		5,313			(1,023	)
Net cash used for investing activities		(90,679	)		(102,918	)
Net increase (decrease) in cash and cash equivalents		46			(7	)
Cash and cash equivalents at beginning of period		41			102
Cash and cash equivalents at end of period	$	87		$	95
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company
are an integral part of these statements.

98

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 June 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2007 and 2006 and the consolidated statement of cash flows for the six-month periods ended June 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

August 6, 2007

99

JERSEY CENTRAL POWER & LIGHT COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND 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 in the second quarter of 2007 increased to $50 million from $40 million in 2006. The increase was primarily due to higher revenues, partially offset by higher purchased power costs, increased amortization of regulatory assets, interest expense and other operating costs. In the first six months of 2007, earnings on common stock increased to $88 million compared to $74 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, increased amortization of regulatory assets and interest expense.

Revenues

Revenues increased $169 million or 27.6% in the second quarter of 2007 and $277 million or 23.3% in the first six months of 2007 compared with the same periods of 2006, reflecting higher retail and wholesale generation revenues. Retail generation revenues increased by $102 million and $164 million in the second quarter and the first six months of 2007, respectively. Wholesale revenues increased $19 million in the second quarter and $27 million in the first six months of 2007.

Generation revenues from all customer classes increased in the second quarter and first six months of 2007 as compared to 2006. The increases in both periods of 2007 were 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 second quarter of 2007 (heating degree days were 35% greater than the second quarter of 2006). Industrial generation KWH sales declined in the second quarter and first six months of 2007 from the same period in 2006 due to an increase in customer shopping.

Wholesale generation revenues increased ($19 million in the second quarter and $27 million in the first six months of 2007) due to higher market prices, partially offset by sales volume decreases of 3.9% and 1.4% from the second quarter and first six months of 2006, respectively.

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

Retail Generation KWH Sales	Three Months			Six Months
Increase (Decrease)
Residential		13.6	%		8.9	%
Commercial		5.3	%		3.2	%
Industrial		(8.4	)%		(4.9	)%
Net Increase in Generation Sales		9.0	%		5.8	%

Retail Generation Revenues	Three Months		Six Months
	(In millions)
Residential	$	64	$	100
Commercial		36		60
Industrial		2		4
Increase in Generation Revenues	$	102	$	164

Distribution revenues increased $39 million and $67 million in the second quarter and first six months of 2007, respectively, compared to the same periods of 2006 due to higher composite unit prices and increased KWH deliveries, reflecting the weather impacts described above. The higher unit prices resulted from a NUGC rate increase effective in December 2006 as approved by the NJBPU.

100

Changes in distribution KWH deliveries and revenues in the second quarter and first six months of 2007 compared to the corresponding periods of 2006 are summarized in the following tables.

Increase in Distribution KWH Deliveries	Three Months			Six Months
Residential		13.7	%		8.9	%
Commercial		5.4	%		4.8	%
Industrial		2.9	%		2.3	%
Total Increase in Distribution Deliveries		8.5	%		6.2	%

Increase in Distribution Revenues	Three Months		Six Months
	(In millions)
Residential	$	24	$	38
Commercial		13		25
Industrial		2		4
Total Increase in Distribution Revenues	$	39	$	67

The higher revenues for the second quarter and first six months of 2007 also included $8 million and $16 million, respectively, of increased revenues resulting from the August 2006 securitization of deferred costs associated with JCP&L’s BGS supply.

Expenses

Total expenses increased by $154 million in the second quarter and $246 million in the first six months of 2007 as compared to the same periods of 2006. The following table presents changes from the prior year by expense category:

Expenses  - Changes	Three Months		Six Months
Increase (Decrease)	(In millions)
Purchased power costs	$	121	$	192
Other operating costs		2		(6	)
Provision for depreciation		1		1
Amortization of regulatory assets		29		57
General Taxes		1		2
Net increase in expenses	$	154	$	246

The increase in purchased power costs (35.4% in the second quarter of 2007 and 29.2% in the first six months) primarily reflected higher unit prices resulting from the BGS auctions. Other operating costs increased $2 million in the second quarter of 2007 due to higher labor costs from storm damage repairs in 2007, but decreased $6 million in the first six months  of 2007 primarily due to lower employee benefit costs. Amortization of regulatory assets increased $29 million in the second quarter and $57 million in the first six months of 2007 due to higher transition cost recovery associated with the December 2006 NUGC rate increase.

Capital Resources and Liquidity

During the remainder of 2007, JCP&L expects to meet its contractual obligations with a combination of cash from operations and short-term borrowings. Borrowing capacity under JCP&L’s credit facilities is available to manage its working capital requirements.

Changes in Cash Position

As of June 30, 2007, JCP&L had $87,000 of cash and cash equivalents compared with $41,000 as of December 31, 2006. The major sources for changes in these balances are summarized below.

101

Cash Flows From Operating Activities

Cash provided from operating activities in the first six months of 2007 compared with the first six months of 2006 were as follows:

	Six Months Ended
	June 30,
Operating Cash Flows	2007			2006
	(In millions)
Net income	$	88		$	74
Net non-cash charges		105			46
Pension trust contribution		(18	)		-
Cash collateral returned to suppliers		(24	)		(109	)
Working capital and other		(243	)		(109	)
Net cash used for operating activities	$	(92	)	$	(98	)

Net cash used for operating activities decreased $6 million in the first six months of 2007 from the same period of 2006. This decrease was primarily due to an $85 million reduction in cash collateral payments made to suppliers in the first six months of 2007 compared to the same period in 2006, an increase of $59 million in non-cash charges and an increase in net income of $14 million. These increases were largely offset by a $134 million decrease from working capital (due to changes in the collection of receivables and tax payments) and an $18 million pension trust contribution in the first quarter of 2007. The changes in net income and non-cash charges are described above in “Results of Operations.”

Cash Flows From Financing Activities

Net cash provided from financing activities was $183 million in the first six months of 2007 compared to $201 million in same period of 2006. The decrease primarily resulted from a $107 million reduction in short-term borrowings, a $125 million repurchase of common stock from FirstEnergy and $147 million of additional long-term debt redemptions, partially offset by a $350 million increase in new long-term debt financing and a $10 million reduction in common stock dividend payments to FirstEnergy.

JCP&Lhad $24 million of cash and temporary investments (which includes short-term notes receivable from associated companies) and approximately $229 million of short-term indebtedness as of June 30, 2007. JCP&L has authorization from the FERC to incur short-term debt up to its charter limit of $431 million (including the utility money pool).

See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of JCP&L’s financing capabilities.

Cash Flows From Investing Activities

Net cash used for investing activities was $91 million in the first six months of 2007 compared to $103 million in the previous year. The $12 million decrease primarily resulted from the absence of $10 million in loans to associated companies in 2006.

During the last half of 2007, capital requirements for property additions and improvements are expected to be about $95 million. These cash requirements are expected to be satisfied from a combination of internal cash and short-term credit arrangements.

JCP&L’s capital spending for the period 2007-2011 is expected to be about $1.3 billion for property additions, of which approximately $192 million applies to 2007.

Market Risk Information

During the first six months of 2007, the value of commodity derivative contracts decreased by $302 million as a result of settled contracts ($196 million) and changes in the value of existing contracts ($106 million). These non-trading contracts (primarily with NUG entities) are adjusted to fair value at the end of each quarter with a corresponding offset to regulatory assets, resulting in no impact to current period earnings.  Commodity derivative contracts were valued at $869 million and $1.2 billion as of June 30, 2007 and December 31, 2006, respectively.  See the “Market Risk Information” section of JCP&L’s 2006 Annual Report on Form 10-K for additional discussion of market risk.

102

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $104 million and $97 million as of June 30, 2007 and December 31, 2006, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $10 million reduction in fair value as of June 30, 2007.

Regulatory Matters

See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to JCP&L.

Environmental Matters

See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to JCP&L.

Other Legal Proceedings

See the “Other Legal Proceedings” section 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.

103

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
	(In thousands)
REVENUES:
Electric sales	$	344,241		$	266,533		$	696,377		$	560,570
Gross receipts tax collections		17,502			15,686			35,622			32,862
Total revenues		361,743			282,219			731,999			593,432
EXPENSES:
Purchased power		182,818			143,070			374,407			302,957
Other operating costs		111,105			59,575			209,123			120,654
Provision for depreciation		10,531			10,288			20,815			21,193
Amortization of regulatory assets		30,972			25,669			65,112			55,717
Deferral of new regulatory assets		(31,895	)		(45,581	)		(74,621	)		(45,581	)
General taxes		20,170			18,595			41,222			39,216
Total expenses		323,701			211,616			636,058			494,156
OPERATING INCOME		38,042			70,603			95,941			99,276
OTHER INCOME (EXPENSE):
Interest income		7,775			8,964			15,501			17,714
Miscellaneous income		1,498			1,792			2,607			4,404
Interest expense		(13,424	)		(12,071	)		(25,180	)		(23,255	)
Capitalized interest		388			344			648			611
Total other expense		(3,763	)		(971	)		(6,424	)		(526	)
INCOME BEFORE INCOME TAXES		34,279			69,632			89,517			98,750
INCOME TAXES		14,809			29,555			38,408			40,759
NET INCOME		19,470			40,077			51,109			57,991
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(1,453	)		-			(2,905	)		-
Unrealized gain on derivative hedges		84			84			168			168
Other comprehensive income (loss)		(1,369	)		84			(2,737	)		168
Income tax expense (benefit) related to other
comprehensive income		(693	)		35			(1,385	)		70
Other comprehensive income (loss), net of tax		(676	)		49			(1,352	)		98
TOTAL COMPREHENSIVE INCOME	$	18,794		$	40,126		$	49,757		$	58,089
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of
these statements.

104

METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,			December 31,
	2007			2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	127		$	130
Receivables-
Customers (less accumulated provisions of $4,480,000 and $4,153,000,
respectively, for uncollectible accounts)		160,147			127,084
Associated companies		27,213			3,604
Other		20,163			8,107
Notes receivable from associated companies		34,399			31,109
Prepaid taxes		23,598			13,533
Other		353			1,424
		266,000			184,991
UTILITY PLANT:
In service		1,945,821			1,920,563
Less - Accumulated provision for depreciation		750,937			739,719
		1,194,884			1,180,844
Construction work in progress		33,474			18,466
		1,228,358			1,199,310
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		283,596			269,777
Other		1,361			1,362
		284,957			271,139
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		496,129			496,129
Regulatory assets		464,434			409,095
Pension assets		23,583			7,261
Other		38,885			46,354
		1,023,031			958,839
	$	2,802,346		$	2,614,279
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	-		$	50,000
Short-term borrowings-
Associated companies		158,731			141,501
Other		197,000			-
Accounts payable-
Associated companies		26,435			100,232
Other		70,566			59,077
Accrued taxes		513			11,300
Accrued interest		7,050			7,496
Other		22,978			22,825
		483,273			392,431
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 900,000 shares-
859,000 shares outstanding		1,276,119			1,276,075
Accumulated other comprehensive loss		(27,868	)		(26,516	)
Accumulated deficit		(183,560	)		(234,620	)
Total common stockholder's equity		1,064,691			1,014,939
Long-term debt and other long-term obligations		542,070			542,009
		1,606,761			1,556,948
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		405,170			387,456
Accumulated deferred investment tax credits		8,830			9,244
Nuclear fuel disposal costs		42,514			41,459
Asset retirement obligations		155,867			151,107
Retirement benefits		17,187			19,522
Other		82,744			56,112
		712,312			664,900
COMMITMENTS AND CONTINGENCIES (Note 9)
	$	2,802,346		$	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.

105

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30,
	2007			2006
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	51,109		$	57,991
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		20,815			21,193
Amortization of regulatory assets		65,112			55,717
Deferred costs recoverable as regulatory assets		(38,540	)		(50,570	)
Deferral of new regulatory assets		(74,621	)		(45,581	)
Deferred income taxes and investment tax credits, net		27,069			22,463
Accrued compensation and retirement benefits		(11,150	)		(4,712	)
Cash collateral		4,850			(2,250	)
Pension trust contribution		(11,012	)		-
Decrease (increase) in operating assets-
Receivables		(64,465	)		38,182
Prepayments and other current assets		(8,994	)		(24,564	)
Increase (decrease) in operating liabilities-
Accounts payable		(62,308	)		6,161
Accrued taxes		(10,788	)		(12,045	)
Accrued interest		(446	)		297
Other		4,238			(4,011	)
Net cash provided from (used for) operating activities		(109,131	)		58,271
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		214,229			-
Redemptions and Repayments-
Long-term debt		(50,000	)		-
Short-term borrowings, net		-			(1,707	)
Net cash provided from (used for) financing activities		164,229			(1,707	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(49,852	)		(47,301	)
Sales of investment securities held in trusts		55,603			113,637
Purchases of investment securities held in trusts		(57,571	)		(118,379	)
Loans to associated companies, net		(3,290	)		(4,054	)
Other		9			(453	)
Net cash used for investing activities		(55,101	)		(56,550	)
Net increase (decrease) in cash and cash equivalents		(3	)		14
Cash and cash equivalents at beginning of period		130			120
Cash and cash equivalents at end of period	$	127		$	134
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral
part of these statements.

106

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 June 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2007 and 2006 and the consolidated statement of cash flows for the six-month periods ended June 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

August 6, 2007

107

METROPOLITAN EDISON COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITIONAND 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 in the second quarter of 2007 decreased to $19 million from $40 million in the second quarter of 2006. The decrease was primarily due to higher purchased power costs, other operating costs and lower deferrals of new regulatory assets due to the May 2006 PPUC order as discussed below, partially offset by higher revenues. For the first six months of 2007, net income decreased to $51 million from $58 million in the same period of 2006. The decrease in the six month period reflects higher purchased power costs and other operating costs, partially offset by higher revenues and increased deferrals of new regulatory assets.

Revenues

Revenues increased by $80 million, or 28.2%, in the second quarter of 2007 and $139 million, or 23.4%, in the first six months of 2007 compared with the same periods of 2006. The increases in both periods were primarily due to higher retail and wholesale generation revenues.

In the second quarter of 2007, retail generation revenues increased by $10 million primarily due to higher KWH sales in the residential and commercial sectors, partially offset by slightly lower KWH sales in the industrial sector. The increase in retail generation revenues in the residential and commercial sectors primarily resulted from higher weather-related usage in the second quarter of 2007 as compared to the same period of 2006 (heating degree days increased by 34.9% and cooling degree days increased by 19.3%).

In the first six months of 2007, retail generation revenues increased by $15 million due to higher KWH sales in all customer sectors. The increase in retail generation revenues in the residential and commercial sectors was primarily due to weather conditions during the first six months of 2007 (heating degree days increased by 18.3% and cooling degree days increased by 19.3% as compared to the same period of 2006).

Increases in retail electric generation sales and revenues in the second quarter and the first six months of 2007 compared to the same periods of 2006 are summarized in the following tables:

Retail Generation KWH Sales	Three Months			Six Months
Increase (Decrease)
Residential		11.7	%		8.7	%
Commercial		4.7	%		4.2	%
Industrial		(0.2	)%		1.3	%
Total Retail Electric Generation Sales		5.6	%		5.0	%

Retail Generation Revenues	Three Months		Six Months
	(In millions)
Residential	$	7	$	10
Commercial		3		5
Industrial		-		-
Increase in Generation Revenues	$	10	$	15

Wholesale revenues increased by $36 million in the second quarter of 2007 and $62 million in the first six months of 2007 compared with the same periods of 2006.  The increases in both periods were due to Met-Ed selling additional available power into the PJM market beginning in January 2007.

108

Revenues from distribution throughput increased by $22 million in the second quarter and $43 million in the first six months of 2007 compared to the same periods in 2006. The increases are due to higher KWH deliveries, reflecting the effect of the weather discussed above, and an increase in composite unit prices resulting from a January 2007 PPUC authorization to increase transmission rates, partially offset by a 5% decrease in distribution rates.

Changes in distribution KWH deliveries and revenues in the second quarter and first six months of 2007 compared to the same periods of 2006 are summarized in the following tables:

Distribution KWH Deliveries	Three Months			Six Months
Residential		11.7	%		8.7	%
Commercial		4.7	%		4.1	%
Industrial		0.5	%		0.7	%
Total Increase in Distribution Deliveries		5.7	%		4.8	%

Distribution Revenues	Three Months		Six Months
	(In millions)
Residential	$	15	$	32
Commercial		2		1
Industrial		5		10
Increase in Distribution Revenues	$	22	$	43

PJM transmission revenues increased by $13 million and $20 million in the second quarter and first six months of 2007, respectively, as a result of higher transmission volumes and additional PJM auction revenue rights, compared to the prior year periods. 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 $112 million and $142 million in the second quarter and first six months of 2007, respectively, compared to the same periods of 2006. The following table presents changes from the prior year by expense category:

Expenses – Changes	Three Months		Six Months
Increase (Decrease)	(In millions)
Purchased power costs	$	40	$	72
Other operating costs		52		88
Amortization of regulatory assets		5		9
Deferral of new regulatory assets		13		(29	)
General taxes		2		2
Net increase in expenses	$	112	$	142

Purchased power costs increased in the second quarter and first six months of 2007 by $40 million and $72 million, respectively, due to increased KWH purchases to source higher generation sales, combined with higher composite unit costs. In the second quarter of 2007, other operating costs increased primarily due to $47 million in higher congestion costs and other transmission expenses associated with the increased transmission volumes discussed above and  $4 million of increased contractor service and labor costs for increased work on reliability-related projects. In the first six months of 2007, other operating costs increased primarily due to higher congestion costs and other transmission expenses ($84 million) and increased customer expenses ($3 million) related to Met-Ed’s customer assistance programs.

Met-Ed’s revenue in the first six months of 2007 included the recovery of a portion of the transmission costs that were deferred in 2006. As a result, amortization of regulatory assets increased in the second quarter and first six months of 2007 compared to the prior year. In the second quarter of 2007, the deferral of new regulatory assets decreased primarily due to higher PJM transmission cost deferrals recognized in the second quarter of 2006. The deferral in the second quarter of 2006 also included PJM Transmission costs incurred in the first quarter following authorization by the PPUC in May 2006. The deferral of new regulatory assets increased in the first six months of 2007 due to the deferral of previously expensed decommissioning costs of $15 million associated with the Saxton nuclear research facility as approved by the PPUC in January 2007 and higher PJM transmission costs and associated interest deferrals.

For both periods, general taxes increased primarily due to higher gross receipts taxes.

109

Capital Resources and Liquidity

During 2007, Met-Ed expects to meet its contractual obligations with a combination of cash from operations and funds from the capital markets. Borrowing capacity under Met-Ed’s credit facilities is available to manage its working capital requirements.

Changes in Cash Position

As of June 30, 2007, Met-Ed had cash and cash equivalents of $127,000 compared with $130,000 as of December 31, 2006. The major sources of changes in these balances are summarized below.

Cash Flows From Operating Activities

Net cash used for operating activities was $109 million in the first six months of 2007 compared to net cash provided from operating activities of $58 million in the same period of 2006, as summarized in the following table:

	Six Months Ended  June 30,
Operating Cash Flows	2007			2006
	(In millions)
Net income	$	51		$	58
Net non-cash charges (credits)		(11	)		(2	)
Pension trust contribution		(11	)		-
Working capital and other		(138	)		2
Net cash provided from (used for) operating activities	$	(109	)	$	58

The decrease from working capital primarily resulted from a $103 million change in receivables, due in part to increased billings associated with the January 2007 rate increase that were delayed until the second quarter of 2007, and a $68 million change in accounts payable, partially offset by a $16 million decrease in prepayments, a $7 million increase in cash collateral received from suppliers and an $8 million increase in cash flows from other operating activities. Changes in net income and non-cash charges (credits) are described above under “Results of Operations.”

Cash Flows From Financing Activities

Net cash provided from financing activities was $164 million in the first six months of 2007 compared to net cash used for financing of $2 million in the first six months of 2006. The increase reflects a $216 million increase in short-term borrowings, offset by a $50 million increase in long-term debt redemptions in the first six months of 2007.

As of June 30, 2007, Met-Ed had approximately $34 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $356 million of short-term borrowings (including $72 million from its receivables financing arrangement and $138 million from money pool borrowings). Met-Ed has authorization from the FERC to incur short-term debt up to $250 million (excluding receivables financing and money pool borrowings) and authorization from the PPUC to incur money pool borrowings up to $300 million.

See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of Met-Ed’s financing capabilities.

Cash Flows From Investing Activities

In the first six months of 2007, Met-Ed's cash used for investing activities totaled $55 million, compared to $56 million in the same period of 2006. The decrease primarily resulted from a reduction in loan repayments to associated companies.

During the last half of 2007, capital requirements for property additions and improvements are expected to be approximately $42 million. This cash requirement is expected to be satisfied from a combination of cash from operations, short-term credit arrangements and funds from the capital markets. Met-Ed's capital spending for the period 2007 through 2011 is expected to be about $520 million, of which approximately $92 million applies to 2007.

In June 2007, Met-Ed entered into an agreement to sell 100% of its ownership interest in York Haven Power Company, pending approval from the PPUC. The sale is subject to regulatory accounting and is not expected to have a material impact on Met-Ed’s earnings.

110

Market Risk Information

During the first six months of 2007, the value of commodity derivative contracts decreased by $5 million as a result of settled contracts ($6 million) and changes in the value of existing contracts ($1 million). These non-trading contracts are adjusted to fair value at the end of each quarter with a corresponding offset to regulatory liabilities, resulting in no impact to current period earnings.  Commodity derivative contracts were valued at $18 million and $23 million as of June 30, 2007 and December 31, 2006, respectively.  See the “Market Risk Information” section of Met-Ed’s 2006 Annual Report on Form 10-K for additional discussion of market risk.

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $175 million and $164 million as of June 30, 2007 and December 31, 2006, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $18 million reduction in fair value as of June 30, 2007.

Regulatory Matters

See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to Met-Ed.

Environmental Matters

See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to Met-Ed.

Other Legal Proceedings

See the “Other Legal Proceedings” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other 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.

111

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
	(In thousands)
REVENUES:
Electric sales	$	315,745		$	250,400		$	654,971		$	526,227
Gross receipts tax collections		15,672			14,599			32,352			30,524
Total revenues		331,417			264,999			687,323			556,751
EXPENSES:
Purchased power		184,494			146,875			385,336			308,516
Other operating costs		58,267			48,133			117,728			86,475
Provision for depreciation		12,335			11,798			24,112			24,441
Amortization of regulatory assets		13,845			12,979			29,239			27,794
Deferral of new regulatory assets		(364	)		(11,815	)		(17,452	)		(11,815	)
General taxes		18,350			17,458			38,201			36,847
Total expenses		286,927			225,428			577,164			472,258
OPERATING INCOME		44,490			39,571			110,159			84,493
OTHER INCOME (EXPENSE):
Miscellaneous income		2,135			1,627			3,552			3,997
Interest expense		(13,072	)		(11,599	)		(24,409	)		(22,135	)
Capitalized interest		285			422			543			769
Total other expense		(10,652	)		(9,550	)		(20,314	)		(17,369	)
INCOME BEFORE INCOME TAXES		33,838			30,021			89,845			67,124
INCOME TAXES		14,375			14,564			38,638			28,518
NET INCOME		19,463			15,457			51,207			38,606
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(2,825	)		-			(5,650	)		-
Unrealized gain on derivative hedges		17			16			33			32
Change in unrealized gain on available for sale securities		(13	)		(14	)		(16	)		(18	)
Other comprehensive income (loss)		(2,821	)		2			(5,633	)		14
Income tax expense (benefit) related to other
comprehensive income		(1,302	)		1			(2,600	)		7
Other comprehensive income (loss), net of tax		(1,519	)		1			(3,033	)		7
TOTAL COMPREHENSIVE INCOME	$	17,944		$	15,458		$	48,174		$	38,613
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral
part of these statements.

112

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,			December 31,
	2007			2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	40		$	44
Receivables-
Customers (less accumulated provisions of $4,216,000 and $3,814,000
respectively, for uncollectible accounts)		143,874			126,639
Associated companies		73,743			49,728
Other		19,809			16,367
Notes receivable from associated companies		18,263			19,548
Prepaid taxes		24,740			3,016
Other		314			1,220
		280,783			216,562
UTILITY PLANT:
In service		2,169,653			2,141,324
Less - Accumulated provision for depreciation		822,098			809,028
		1,347,555			1,332,296
Construction work in progress		28,719			22,124
		1,376,274			1,354,420
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		133,103			125,216
Non-utility generation trusts		101,240			99,814
Other		531			531
		234,874			225,561
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		860,716			860,716
Pension assets		31,293			11,474
Other		32,785			36,059
		924,794			908,249
	$	2,816,725		$	2,704,792
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Short-term borrowings-
Associated companies	$	166,534		$	199,231
Other		199,000			-
Accounts payable-
Associated companies		23,354			92,020
Other		46,225			47,629
Accrued taxes		2,920			11,670
Accrued interest		7,404			7,224
Other		21,703			21,178
		467,140			378,952
CAPITALIZATION:
Common stockholder's equity-
Common stock, $20 par value, authorized 5,400,000 shares-
5,290,596 shares outstanding		105,812			105,812
Other paid-in capital		1,189,479			1,189,434
Accumulated other comprehensive loss		(10,226	)		(7,193	)
Retained earnings		116,165			90,005
Total common stockholder's equity		1,401,230			1,378,058
Long-term debt and other long-term obligations		477,704			477,304
		1,878,934			1,855,362
NONCURRENT LIABILITIES:
Regulatory liabilities		73,990			96,151
Asset retirement obligations		79,348			76,924
Accumulated deferred income taxes		185,969			193,662
Retirement benefits		50,974			50,328
Other		80,370			53,413
		470,651			470,478
COMMITMENTS AND CONTINGENCIES (Note 9)
	$	2,816,725		$	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.

113

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30,
	2007			2006
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	51,207		$	38,606
Adjustments to reconcile net income to net cash from operating activities
Provision for depreciation		24,112			24,441
Amortization of regulatory assets		29,239			27,794
Deferral of new regulatory assets		(17,452	)		(11,815	)
Deferred costs recoverable as regulatory assets		(34,691	)		(54,092	)
Deferred income taxes and investment tax credits, net		13,548			13,206
Accrued compensation and retirement benefits		(12,130	)		893
Cash collateral		3,250			-
Pension trust contribution		(13,436	)		-
Decrease (increase) in operating assets
Receivables		(39,530	)		30,485
Prepayments and other current assets		(20,819	)		(18,565	)
Increase (decrease) in operating liabilities
Accounts payable		(70,070	)		(9,008	)
Accrued taxes		(8,750	)		(10,756	)
Accrued interest		181			190
Other		1,377			8,817
Net cash provided from (used for) operating activities		(93,964	)		40,196
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing
Short-term borrowings, net		166,303			26,642
Dividend Payments
Common stock		(25,000	)		-
Net cash provided from financing activities		141,303			26,642
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(43,904	)		(60,747	)
Loan repayments from (loans to) associated companies, net		1,285			(3,466	)
Sales of investment securities held in trust		26,882			60,650
Purchases of investment securities held in trust		(29,610	)		(60,650	)
Other, net		(1,996	)		(2,611	)
Net cash used for investing activities		(47,343	)		(66,824	)
Net increase (decrease) in cash and cash equivalents		(4	)		14
Cash and cash equivalents at beginning of period		44			35
Cash and cash equivalents at end of period	$	40		$	49
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an
integral part of these statements.

114

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 June 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2007 and 2006 and the consolidated statement of cash flows for the six-month periods ended June 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

August 6, 2007

115

PENNSYLVANIA ELECTRIC COMPANY

MANAGEMENT’S DISCUSSION ANDANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Results of Operations

Net income in the second quarter of 2007 increased to $19 million, compared to $15 million in the second quarter of 2006. This increase resulted from higher revenues partially offset by higher purchased power costs, other operating costs and lower deferrals of new regulatory assets due to the May 2006 PPUC order discussed below. In the first six months of 2007, net income increased to $51 million, compared to $39 million in the first six months of 2006. This increase in net income was due to higher revenues and deferrals of new regulatory assets, partially offset by increased purchased power costs and other operating costs.

Revenues

Revenues increased by $66 million, or 25.1%, in the second quarter of 2007 and $131 million, or 23.5%, in the first six months of 2007. The increases in both periods were primarily due to higher retail and wholesale generation revenues.

Retail generation revenues increased by $6 million in the second quarter of 2007 primarily due to higher KWH sales to residential and commercial customers. The increase in retail generation revenues in the residential and commercial classes was primarily due to higher weather-related usage in the second quarter of 2007 compared to the second quarter of 2006 (heating degree days increased 6.2% and cooling degree days increased 58.5%).

Retail generation revenues increased $12 million for the first six 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 due to weather conditions in the first six months of 2007 (heating degree days increased 12.5% and cooling degree days increased 58.5% as compared to the same time period of 2006).

Increases in retail electric generation sales and revenues in the second quarter and first six months of 2007 compared to the corresponding periods of 2006 are summarized in the following tables:

Retail Generation KWH Sales	Three Months			Six Months
Increase (Decrease)
Residential		5.2	%		5.5	%
Commercial		4.9	%		5.0	%
Industrial		(0.1	)%		-
Total Retail Electric Generation Sales		3.3	%		3.6	%

Retail Generation Revenues	Three Months		Six Months
	(In millions)
Residential	$	3	$	6
Commercial		3		6
Industrial		-		-
Increase in Retail Generation Revenues	$	6	$	12

Wholesale revenues increased $39 million in the second quarter of 2007 and $74 million in the first six months of 2007, compared with the same periods of 2006 due to Penelec selling additional available power into the PJM market beginning in January 2007.

Revenues from distribution throughput increased $13 million in the second quarter and $29 million in the first six months of 2007 due to higher KWH deliveries reflecting the effect of the weather discussed above and an increase in composite unit prices resulting from a January 2007 PPUC authorization to increase transmission rates, partially offset by a 4.5% decrease in distribution rates.

116

Changes in distribution KWH deliveries and revenues in the second quarter and first six months of 2007 compared to the same periods in 2006 are summarized in the following tables:

Distribution KWH Deliveries	Three Months			Six Months
Increase (Decrease)
Residential		5.2	%		5.5	%
Commercial		4.9	%		5.0	%
Industrial		-			(0.9	)%
Total Distribution Deliveries		3.2	%		3.1	%

Distribution  Revenues	Three Months			Six Months
Increase (Decrease)	(In millions)
Residential	$	13		$	30
Commercial		(1	)		(3	)
Industrial		1			2
Total Distribution Revenues	$	13		$	29

PJM transmission revenues increased by $9 million in the second quarter of 2007 and $15 million in the first six 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 $62 million in the second quarter of 2007 and $105 million in the first six months of 2007 compared with the same periods in 2006. The following table presents changes from the prior year by expense category:

	Three		Six
Expenses - Changes	Months		Months
	(In millions)
Increase (Decrease)
Purchased power costs	$	38	$	77
Other operating costs		10		31
Provision for depreciation		1		-
Amortization of regulatory assets		1		1
Deferral of new regulatory assets		11		(5	)
General taxes		1		1
Net increase in expenses	$	62	$	105

Purchased power costs increased by $38 million, or 25.6%, in the second quarter of 2007 and $77 million, or 24.9%, in the first six months of 2007, compared to the same period of 2006. The increases were due primarily to higher KWH purchases to source higher retail and wholesale generation sales combined with higher composite unit costs. Other operating costs increased by $9 million in the second quarter of 2007 and $32 million in the first six months of 2007 principally due to higher congestion costs and other transmission expenses associated with the increased transmission volumes discussed above.

In the second quarter of 2007, the deferral of new regulatory assets decreased primarily due to higher PJM transmission cost deferrals recognized in the second quarter of 2006. The deferral in the second quarter of 2006 also included PJM transmission costs incurred in the first quarter following authorization by the PPUC in May 2006. The deferral of new regulatory assets increased in the first six months of 2007 due to the deferral of previously expensed decommissioning costs of $12 million associated with the Saxton nuclear research facility as approved by the PPUC in January 2007,partially offset by lower PJM transmission cost deferrals.

Capital Resources and Liquidity

During 2007, Penelec expects to meet its contractual obligations with a combination of cash from operations and funds from the capital markets. Borrowing capacity under Penelec’s credit facilities is available to manage its working capital requirements.

117

Changes in Cash Position

As of June 30, 2007, Penelec had $40,000 of cash and cash equivalents compared with $44,000 as of December 31, 2006. The major sources for changes in these balances are summarized below.

Cash Flows From Operating Activities

Net cash provided (used) for operating activities in the second quarter of 2007 and 2006 were as follows:

	Six Months Ended
	June 30,
Operating Cash Flows	2007			2006
	(In millions)
Net income	$	51		$	39
Net non-cash charges		3			-
Pension trust contribution		(13	)		-
Working capital and other		(135	)		1
Net cash provided from (used for) operating activities	$	(94	)	$	40

The $136 million change from working capital principally resulted from a $70 million change in accounts receivable due in part to increased billings associated with the January 2007 rate increase that were delayed until the second quarter of 2007, increased cash payments of $61 million for accounts payable and $8 million in increased cash outflows from other operating activities partially offset by a $3 million increase in cash collateral received from suppliers. Changes in net income and non-cash charges are described under “Results of Operations.”

Cash Flows From Financing Activities

Net cash provided from financing activities was $141 million in the first six months of 2007 compared to $26 million in the first six months of 2006. The increase reflects a $140 million increase in short-term borrowings, partially offset by a $25 million increase in common stock dividend payments to FirstEnergy.

Penelec had approximately $18 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $366 million of short-term indebtedness (including $74 million from its receivables financing arrangement and $167 million in money pool borrowings) as of June 30, 2007. Penelec has authorization from the FERC to incur short-term debt of up to $250 million (excluding receivables financing and money pool borrowings) and authorization from the PPUC to incur money pool borrowings of up to $300 million.

See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of Penelec’s financing capabilities.

Cash Flows From Investing Activities

In the first six months of 2007, net cash used for investing activities totaled $47 million compared to $67 million in the first six months of 2006. The decrease primarily resulted from a $17 million decrease in property additions and a $5 million increase in loan repayments from associated companies, partially offset by a $3 million increase in the investments in the nuclear decommissioning trust fund.

During the last half of 2007, capital requirements for property additions are expected to be about $46 million. Penelec’s capital spending for the period 2007-2011 is expected to be about $614 million, of which approximately $92 million applies to 2007.

Market Risk Information

During the first six months of 2007, the value of commodity derivative contracts decreased by $2 million as a result of settled contracts. These non-trading contracts are adjusted to fair value at the end of each quarter with a corresponding offset to regulatory liabilities, resulting in no impact to current period earnings. Commodity derivative contracts were valued at $10 million and $12 million as of June 30, 2007 and December 31, 2006, respectively. See the “Market Risk Information” section of Penelec’s 2006 Annual Report on Form 10-K for additional discussion of market risk.

118

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $80 million and $72 million as of June 30, 2007 and December 31, 2006, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $8 million reduction in fair value as of June 30, 2007.

Regulatory Matters

See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to Penelec.

Environmental Matters

See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to Penelec.

Other Legal Proceedings

See the “Other Legal Proceedings” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other 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.

119

COMBINED MANAGEMENT’S DISCUSSION

AND ANALYSIS OF REGISTRANT SUBSIDIARIES

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

Financing Capability  (Applicable to each of the Companies)

As of June 30, 2007, OE, CEI and TE had the capability to issue approximately $1.5 billion, $557 million and $797 million, respectively, 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 $463 million, $515 million and $127 million, respectively, as of June 30, 2007. Because 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, it is no longer required to issue FMBs as collateral for senior notes and therefore is not limited as to the amount of senior notes it may issue.

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

As of June 30, 2007, OE had approximately $400 million of capacity remaining unused under its existing 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			39
CEI		250	(3)		500
TE		250	(3)		500
JCP&L		425			431
Met-Ed		250			250	(4)
Penelec		250			250	(4)

⁽¹⁾ As of June 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.

120

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 June 30, 2007, FirstEnergy and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:

Borrower
FirstEnergy	61	%
OE*	48	%
Penn	24	%
CEI*	60	%
TE*	56	%
JCP&L	32	%
Met-Ed	46	%
Penelec*	38	%

*The ratios of June 30, 2007, as adjusted for common stock dividends declared

in July 2007 would be: OE – 50%, CEI – 63%, TE – 61% and Penelec – 39%.

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.

The Companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. FESC administers the money pool and tracks surplus funds of FirstEnergy and the Companies, 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 the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first six months of 2007 was 5.64%.

Each of the Companies’ access to capital markets and costs of financing are influenced by the ratings of its securities and the securities of FirstEnergy.  The following table displays FirstEnergy’s and the Companies’ securities ratings as of June 30, 2007. The ratings outlook from Moody’s is positive for all securities. The ratings outlook from S&P on all securities is stable.  The ratings outlook from Fitch on CEI and TE is positive and stable on all other operating companies.

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

OE, CEI, Penn, Met-Ed and Penelec each have a wholly owned subsidiary whose borrowings are secured by customer accounts receivable purchased from its respective parent company. The CEI subsidiary's borrowings are also secured by customer accounts receivable purchased from TE. Each subsidiary company has its own receivables financing arrangement and, as a separate legal entity with separate creditors, would have to satisfy its obligations to creditors before any of its remaining assets could be available to its parent company. The receivables financing borrowing capacity and outstanding balance by company, as of June 30, 2007, are shown in the following table.

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Subsidiary Company	Parent Company		Borrowing Capacity		Outstanding Balance	Annual Facility Fee
	(In millions)
OES Capital, Incorporated	OE	$	170	$	100	0.15%
Centerior Funding Corp.	CEI		200		-	0.15
Penn Power Funding LLC	Penn		25		17	0.125
Met-Ed Funding LLC	Met-Ed		80		72	0.125
Penelec Funding LLC	Penelec		75		74	0.125
		$	550	$	263

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 customers to select a competitive electric generation supplier other than the Companies;

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

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

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

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

·     requiring corporate separation of regulated and unregulated business activities.

The Companies recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $219 million as of June 30, 2007 (JCP&L - $103 million, Met-Ed - $34 million and Penelec - $82 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:

	June 30,		December 31,		Increase
Regulatory Assets*	2007		2006		(Decrease)
	(In millions)
OE	$	733	$	741	$	(8	)
CEI		863		855		8
TE		230		248		(18	)
JCP&L		1,825		2,152		(327	)
Met-Ed		464		409		55
Total	$	4,115	$	4,405	$	(290	)

* Penelec had net regulatory liabilities of approximately $74 million and $96 million as of June 30, 2007 and December 31, 2006, respectively. These net regulatory liabilities are included in Other Non-current Liabilities on the Consolidated Balance Sheets.

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Ohio  (Applicable to OE, CEI and TE) 

On October 21, 2003, the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to the PUCO’s concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming the PUCO's order in all respects, except it remanded back to the PUCO the matter of ensuring the availability of sufficient means for customer participation in the marketplace. The RSP contained a provision that permitted the Ohio Companies to withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies have 30 days from the final order or decision to provide notice of termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding on Remand. In their Request, the Ohio Companies provided notice of termination to those provisions of the RSP subject to termination, subject to being withdrawn, and also set forth a framework for addressing the Supreme Court of Ohio’s findings on customer participation. If the PUCO approves a resolution to the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and considered to be null and void. On July 20, 2006, the OCC and NOAC also submitted to the PUCO a conceptual proposal addressing the issue raised by the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry directing the Ohio Companies to file a plan in a new docket to address the Court’s concern. The Ohio Companies filed their RSP Remand CBP on September 29, 2006. Initial comments were filed on January 12, 2007 and reply comments were filed on January 29, 2007. In their reply comments the Ohio Companies described the highlights of a new tariff offering they would be willing to make available to customers that would allow customers to purchase renewable energy certificates associated with a renewable generation source, subject to PUCO approval. On May 29, 2007, the Ohio Companies, together with the PUCO Staff and the OCC, filed a stipulation with the PUCO agreeing to offer a standard bid product and a green resource tariff product. The stipulation is currently pending before the PUCO. No further proceedings are scheduled at this time.

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	$	179	$	108	$	93	$	380
2008		208		124		119		451
2009		-		216		-		216
2010		-		273		-		273
Total Amortization	$	387	$	721	$	212	$	1,320

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 provided an update 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 late 2007. The PUCO order is expected to be issued by March 9, 2008. The new rates, subject to evidentiary hearings and approval at the PUCO, 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 Ohio Companies requested that the PUCO issue an order by November 1, 2007, to provide sufficient time to conduct the bidding process. The PUCO has scheduled a technical conference for August 16, 2007.

Pennsylvania  (Applicable to 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 costs during the term of these agreements with FES.

On April 7, 2006, the parties entered into a tolling agreement that arose from FES’ notice to Met-Ed and Penelec that FES elected to exercise its right to terminate the partial requirements agreement effective midnight December 31, 2006. On November 29, 2006, Met-Ed, Penelec and FES agreed to suspend the April 7 tolling agreement pending resolution of the PPUC’s proceedings regarding the Met-Ed and Penelec comprehensive transition rate cases filed April 10, 2006, described below. Separately, 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 substantially exceed 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 tolling, suspension and 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.

Met-Ed and Penelec made a comprehensive 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 in accordance with the April 7, 2006 tolling agreement described above. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs, but only for those 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 the merger savings, with the comprehensive transmission rate filing case.

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The PPUC entered its Opinion and Order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, 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 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 by all parties. Responsive briefs are due August 20, 2007, with reply briefs due September 4, 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 June 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 $493 million and $127 million, respectively. $82 million of Penelec’s deferral is subject to final resolution of an IRS settlement associated with NUG trust fund proceeds. 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 late 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 would be provided through an hourly-priced service provided by Penn. Quarterly reconciliation of the differences between the costs of supply and revenues from customers is also proposed. The PPUC is requested to act on the proposal no later than November 2007 for the initial RFP to take place in January 2008.

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On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation 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 will be 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 June 30, 2007, the accumulated deferred cost balance totaled approximately $392 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 Energy Master Plan (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;

·       Unit prices for electricity should remain 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.

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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 August 1, 2007, the NJBPU approved publication of a formal proposal in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following a period for public comment.  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 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 third 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 and Electric Company 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 American Electric Power Company, Inc., 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.

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.

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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 maintain existing transmission rates between MISO and PJM.  If accepted 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 transmission facilities across the entire MISO footprint be maintained.  All of these filings were supported by the majority of transmission owners in either MISO or PJM.

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 transmission facilities be spread throughout the entire MISO footprint.  If adopted by the FERC, this proposal would shift a greater portion of the cost of new 345 kV transmission facilities to the FirstEnergy footprint, and increase the transmission rates paid by load-serving FirstEnergy affiliates.

American Electric Power (AEP) filed a letter with the FERC Commissioners stating its intent to file a complaint under Section 206 of the Federal Power Act challenging the justness and reasonableness of the rate designs underlying the MISO and PJM transmission tariffs.  AEP will propose the adoption of a regional rate design that is expected to reallocate the cost of both existing and new high voltage transmission facilities across the combined MISO and PJM footprint.  Based upon the position advocated by AEP in a related proceeding, the AEP proposal is expected to result in a greater allocation of costs to FirstEnergy transmission zones in MISO and PJM.  If approved by the FERC, AEP’s proposal would increase the transmission rates paid by load-serving FirstEnergy affiliates.

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.

On February 15, 2007, MISO filed documents with the FERC to establish a market-based, competitive ancillary services market.  MISO contends that the filing will integrate operating reserves into MISO’s existing day-ahead and real-time settlements process, incorporate opportunity costs into these markets, address scarcity pricing through the implementation of a demand curve methodology, foster demand response in the provision of operating reserves, and provide for various efficiencies and optimization with regard to generation dispatch.  The filing also proposes amendments to existing documents to provide for the transfer of balancing functions from existing local balancing authorities to MISO.  MISO will then carry out this reliability function as the NERC-certified balancing authority for the MISO region with implementation in the third or fourth quarter of 2008.  FirstEnergy filed comments on March 23, 2007, supporting the ancillary service market in concept, but proposing certain changes in MISO’s proposal. MISO requested FERC action on its filing by June 2007 and the FERC issued its Order June 22, 2007. The FERC found MISO’s filing to be deficient in two key areas: (1) MISO has not submitted a market power analysis in support of its proposed Ancillary Services Market and (2) MISO has not submitted a readiness plan to ensure reliability during the transition from the current reserve and regulation system managed by the individual Balancing Authorities to a centralized Ancillary Services Market managed by MISO. MISO was ordered to remedy these deficiencies and the FERC provided more guidance on other issues brought up in filings by stakeholders to assist MISO to re-file a complete proposal. This Order should facilitate MISO’s timetable to incorporate final revisions to ensure a market start in Spring 2008. FirstEnergy will be participating in working groups and task forces to ensure the Spring 2008 implementation of the Ancillary Services Market.

On February 16, 2007, the FERC issued a final rule 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. As market participants in both MISO and PJM, the Companies will conform their business practices to each respective revised tariff.

Environmental Matters (Applicable to each of the Companies)

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 the Companies’ determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.

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Regulation of Hazardous Waste

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 June 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 $88 million (JCP&L - $60 million, TE - $3 million, CEI - $1 million, and other subsidiaries - $24 million) have been accrued through June 30, 2007.

W. H. Sammis Plant  (Applicable to 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 FGCO 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.

Other Legal Proceedings (Applicable to each of the Companies)

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

Power Outages and Related Litigation

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

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In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision on July 8, 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, on March 7, 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 on May 9, 2007.  Proceedings are continuing in the Superior Court.  FirstEnergy is vigorously defending this class action but is unable to predict the outcome of this matter.  No liability has been accrued as of June 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., 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 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.

On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga County Common Pleas Court seeking reimbursement for claims paid to numerous insureds who allegedly suffered losses as a result of the August 14, 2003 outages. All of the insureds appear to be non-customers. The plaintiff insurance companies are the same claimants in one of the pending PUCO cases. FirstEnergy, the Ohio Companies and Penn were served on October 27, 2006.  On January 18, 2007, the Court granted the Companies’ motion to dismiss the case and they have not been appealed.  However, on April 25, 2007, one of the insurance carriers refiled the complaint naming only FirstEnergy as the defendant.  On July 30, 2007, the case was voluntarily dismissed.  No estimate of potential liability is available for any of these cases.

FirstEnergy was also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy were based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. None of FirstEnergy’s subsidiaries serve customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss. The plaintiff has not appealed.

FirstEnergy is vigorously 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 the Companies were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or the Companies' financial condition, results of operations and cash flows.

Other Legal Matters

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 plaintiff’s motion to amend their complaint which OE has opposed.

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. JCP&L intends to re-file an appeal 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. The parties met on June 27, 2007 before an arbitrator to assert their positions regarding the finality of damages. A hearing before the arbitrator is set for September 7, 2007.

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If it were ultimately determined that FirstEnergy or the Companies 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 the Companies’ financial condition, results of operations and cash flows.

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

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. The Companies are currently evaluating the impact of this Statement on their financial statements.

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. 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 the Companies’ financial statements.

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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 June 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 9 and 10 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 June 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
	April 1-30,		May 1-31,		June 1-30,		Second
	2007		2007		2007		Quarter
Total Number of Shares Purchased (a)	194,553		304,287		219,445		718,285
Average Price Paid per Share	$68.41		$71.09		$68.12		$69.46
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    Comp ensation 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.

ITEM 4.                      SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

(a) The annual meeting of FirstEnergy shareholders was held on May 15, 2007.

(b) At this meeting, the following persons were elected to FirstEnergy's Board of Directors for one-year terms:

	Number of Votes
	For		Withheld
Paul T. Addison		188,720,311		74,174,290
Anthony J. Alexander		188,700,783		74,193,818
Michael J. Anderson		249,806,449		13,088,152
Dr. Carol A. Cartwright		159,733,696		103,160,905
William T. Cottle		166,930,916		95,963,685
Robert B. Heisler, Jr.		190,762,159		72,132,442
Ernest J. Novak, Jr.		188,312,120		74,582,481
Catherine A. Rein		188,486,982		74,407,619
George M. Smart		166,422,193		96,472,408
Wes M. Taylor		188,651,197		74,243,404
Jesse T. Williams, Sr.		166,684,440		96,210,161

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The following Directors retired from the Board effective May 15, 2007: Russell W. Maier and Robert C. Savage.

(c) (i) At this meeting, the appointment of PricewaterhouseCoopers LLP, an independent registered public accounting firm, as auditor for the year 2007 was ratified:

Number of Votes
For	Against		Abstentions
258,877,611		1,368,549		2,648,441

(ii) At this meeting, the FirstEnergy Corp. 2007 Incentive Plan was approved:

Number of Votes
					Broker
For	Against		Abstentions		Non-Votes
207,313,123		23,286,182		3,901,643		28,393,653

  (iii) At this meeting, a shareholder proposal recommending that the Board of Directors change the company’s jurisdiction from Ohio to Delaware was not approved (approval required a favorable vote of a majority of the votes cast):

Number of Votes
					Broker
For	Against		Abstentions		Non-Votes
80,014,916		149,489,965		5,026,051		28,363,669

  (iv) At this meeting, a shareholder proposal recommending that the Board of Directors adopt a policy establishing an engagement process with proponents of shareholder proposals that are supported by a majority of the votes cast was not approved (approval required a favorable vote of a majority of the votes cast):

Number of Votes
					Broker
For	Against		Abstentions		Non-Votes
91,938,193		137,204,324		5,358,416		28,393,668

  (v) At this meeting, a shareholder proposal recommending that the Board of Directors adopt simple majority shareholder voting was approved (approval required a favorable vote of a majority of the votes cast):

Number of Votes
					Broker
For	Against		Abstentions		Non-Votes
175,884,412		53,721,749		4,893,976		28,394,464

Based on this result, the Board of directors will further review this proposal

and consider the appropriate steps to take in response.

ITEM 6.                      EXHIBITS

Exhibit Number
FirstEnergy
	10-1	Participation Agreement, dated as of June 26, 2007, among FirstEnergy Generation Corp., as Lessee, FirstEnergy Solutions Corp., as Guarantor,  the applicable Lessor, U.S. Bank Trust National Association, as Trust Company, the applicable Owner Participant, The Bank of New York Trust Company, N.A., as Indenture Trustee, and The Bank of New York Trust Company, N.A., as Pass Through Trustee(1)(2)

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10-2	Trust Agreement, dated as of June 26, 2007 between the applicable Owner Participant and U.S. Bank Trust National Association, as Owner Trustee(1)(2)
10-3	Indenture of Trust, Open-End Mortgage and Security Agreement, dated as of July 1, 2007, between the applicable Lessor and The Bank of New York Trust Company, N.A., as Indenture Trustee(1)(2)
10-4	6.85% Lessor Note due 2034(1)(2) (included in Exhibit 10-3)
10-5	Bill of Sale and Transfer, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor(1)(2)
10-6	Facility Lease Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor(1)(2)
10-7	Site Lease, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor(1)(2)
10-8	Site Sublease, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor(1)(2)
10-9	Guaranty of FirstEnergy Solutions Corp., dated as of July 1, 2007(1)(2)
10-10	Support Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor(1)(2)
10-11	Second Amendment to the Bruce Mansfield Units 1, 2, and 3 Operating Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp., The Cleveland Electric Illuminating Company, and The Toledo Edison Company(1)
10-12	Pass Through Trust Agreement, dated as of June 26, 2007, among FirstEnergy Generation Corp., FirstEnergy Solutions Corp., and The Bank of New York Trust Company, N.A., as Pass Through Trustee(1)
10-13	6.85% Pass Through Trust Certificate due 2034(1)(2) (included in Exhibit 10-12)
10-14	Registration Rights Agreement, dated as of July 13, 2007, among FirstEnergy Generation Corp., FirstEnergy Solutions Corp., The Bank of New York Trust Company, N.A., as Pass Through Trustee, Morgan Stanley & Co. Incorporated, and Credit Suisse Securities (USA) LLC, as representatives of the several initial purchasers(1)
12	Fixed charge ratios
15	Letter from independent registered public accounting firm
31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a).
31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a).
32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

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
	3	Jersey Central Power & Light Company By-Laws, as amended July 11, 2007
	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.

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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
	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.

⁽¹⁾ Incorporated by reference to the Registrant’s Form 8-K/A filed on August 2, 2007.

⁽²⁾ Pursuant to the Instructions to Item 601(a), the Registrant has omitted the indentures, contracts and other documents required to be filed as exhibits since they are substantially identical in all material respects except as to the parties thereto and certain other details as noted in the schedule filed as Exhibit 99-1 to the Registrant’s Form 8-K/A file on August 2, 2007. The Registrant agrees to furnish these items at the request of the SEC.

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

August 7, 2007

FIRSTENERGY 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)

138