Firstenergy 10Q 2005 Q2 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

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

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2005

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

SECURITIES EXCHANGE ACT OF 1934

For the transition period from

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

1-3491	PENNSYLVANIA POWER COMPANY	25-0718810
	(A Pennsylvania 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 each registrant is an accelerated filer (as defined in Rule 12b-2 of the Act):

YesX	No	FirstEnergy Corp.
Yes	NoX	Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company

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

	OUTSTANDING
CLASS	AS OF AUGUST 1, 2005
FirstEnergy Corp., $.10 par value	329,836,276
Ohio Edison Company, no par value	100
The Cleveland Electric Illuminating Company, no par value	79,590,689
The Toledo Edison Company, $5 par value	39,133,887
Pennsylvania Power Company, $30 par value	6,290,000
Jersey Central Power & Light Company, $10 par value	15,371,270
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. Ohio Edison Company is the sole holder of Pennsylvania Power Company common stock.

This combined Form 10-Q is separately filed by FirstEnergy Corp., Ohio Edison Company, Pennsylvania Power 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 our regulated utilities to collect transition and other charges, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), the uncertainty of the timing and amounts of the capital expenditures (including that such amounts could be higher than anticipated) or levels of emission reductions related to the settlement agreement resolving the New Source Review litigation, adverse regulatory or legal decisions and outcomes (including revocation of necessary licenses or operating permits, fines or other enforcement actions and remedies) of government investigations and oversight, including by the Securities and Exchange Commission, the United States Attorney’s Office and the Nuclear Regulatory Commission as disclosed in the registrants’ Securities and Exchange Commission filings, generally, and with respect to the Davis-Besse Nuclear Power Station outage and heightened scrutiny at the Perry Nuclear Power Plant in particular, the availability and cost of capital, the continuing availability and operation of generating units, the inability to accomplish or realize anticipated benefits of strategic goals, 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, the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the August 14, 2003 regional power outage, the final outcome in the proceeding related to FirstEnergy's Application for a Rate Stabilization Plan in Ohio, the risks and other factors discussed from time to time in the registrants' Securities and Exchange Commission filings, including their annual report on Form 10-K for the year ended December 31, 2004, and other similar factors. The registrants expressly disclaim any current intention to update any forward-looking statements contained in this document 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 Results of Operation and Financial Condition

	Notes to Consolidated Financial Statements	1-23

FirstEnergy Corp.

	Consolidated Statements of Income	24
	Consolidated Statements of Comprehensive Income	25
	Consolidated Balance Sheets	26
	Consolidated Statements of Cash Flows	27
	Report of Independent Registered Public Accounting Firm	28
	Management's Discussion and Analysis of Results of Operations and	29-60
	Financial Condition

Ohio Edison Company

	Consolidated Statements of Income and Comprehensive Income	61
	Consolidated Balance Sheets	62
	Consolidated Statements of Cash Flows	63
	Report of Independent Registered Public Accounting Firm	64
	Management's Discussion and Analysis of Results of Operations and	65-75
	Financial Condition

The Cleveland Electric Illuminating Company

	Consolidated Statements of Income and Comprehensive Income	76
	Consolidated Balance Sheets	77
	Consolidated Statements of Cash Flows	78
	Report of Independent Registered Public Accounting Firm	79
	Management's Discussion and Analysis of Results of Operations and	80-90
	Financial Condition

The Toledo Edison Company

	Consolidated Statements of Income and Comprehensive Income	91
	Consolidated Balance Sheets	92
	Consolidated Statements of Cash Flows	93
	Report of Independent Registered Public Accounting Firm	94
	Management's Discussion and Analysis of Results of Operations and	95-104
	Financial Condition

Pennsylvania Power Company

	Consolidated Statements of Income and Comprehensive Income	105
	Consolidated Balance Sheets	106
	Consolidated Statements of Cash Flows	107
	Report of Independent Registered Public Accounting Firm	108
	Management's Discussion and Analysis of Results of Operations and	109-116
	Financial Condition

TABLE OF CONTENTS (Cont'd)

		Pages


Jersey Central Power & Light Company

	Consolidated Statements of Income and Comprehensive Income	117
	Consolidated Balance Sheets	118
	Consolidated Statements of Cash Flows	119
	Report of Independent Registered Public Accounting Firm	120
	Management's Discussion and Analysis of Results of Operations and	121-128
	Financial Condition

Metropolitan Edison Company

	Consolidated Statements of Income and Comprehensive Income	129
	Consolidated Balance Sheets	130
	Consolidated Statements of Cash Flows	131
	Report of Independent Registered Public Accounting Firm	132
	Management's Discussion and Analysis of Results of Operations and	133-139
	Financial Condition

Pennsylvania Electric Company

	Consolidated Statements of Income and Comprehensive Income	140
	Consolidated Balance Sheets	141
	Consolidated Statements of Cash Flows	142
	Report of Independent Registered Public Accounting Firm	143
	Management's Discussion and Analysis of Results of Operations and	144-150
	Financial Condition

Item 3. Quantitative and Qualitative Disclosures About Market Risk		151

Item 4. Controls and Procedures		151

Part II. Other Information

Item 1. Legal Proceedings		152

Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities		152

Item 4. Submission of Matters to a Vote of Security Holders		152

Item 6. Exhibits		153-168

GLOSSARY OF TERMS

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

ATSI	American Transmission Systems, Incorporated, owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
CFC	Centerior Funding Corporation, a wholly owned finance subsidiary of CEI
Companies	OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec
EUOC	Electric Utility Operating Companies (OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec, and ATSI)
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., operates nonnuclear generating facilities
FirstCom	First Communications, LLC, provides local and long-distance telephone service
FirstEnergy	FirstEnergy Corp., a registered public utility holding company
FSG	FirstEnergy Facilities Services Group, LLC, the 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	JCP&L Transition Funding 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.
OE	Ohio Edison Company, an Ohio electric utility operating subsidiary
OE Companies	OE and Penn
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	Termobarranguilla S. A., Empresa de Servicios Publicos

The following abbreviations and acronyms are used to identify frequently used terms in this report:

AOCL	Accumulated Other Comprehensive Loss
APB	Accounting Principles Board
APB 25	APB Opinion No. 25, "Accounting for Stock Issued to Employees"
APB 29	APB Opinion No. 29, "Accounting for Nonmonetary Transactions"
ARO	Asset Retirement Obligation
BGS	Basic Generation Service
CAIR	Clean Air Interstate Rule
CO₂	Carbon Dioxide
CTC	Competitive Transition Charge
ECAR	East Central Area Reliability Coordination Agreement
EITF	Emerging Issues Task Force
EITF 03-1	EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its Application to Certain
	Investments"
EITF 04-13	EITF Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"
EITF 99-19	EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent"
EPA	Environmental Protection Agency
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	FASB Interpretation 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"
FMB	First Mortgage Bonds
FSP	FASB Staff Position

iii

FSP EITF 03-1-1	FASB Staff Position No. EITF Issue 03-1-1, "Effective Date of Paragraphs 10-20 of EITF Issue
	No. 03-1, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain
	Investments"
FSP 109-1	FASB Staff Position No. 109-1, "Application of FASB Statement No. 109, Accounting for Income
	Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs
	Creation Act of 2004"
GAAP	Accounting Principles Generally Accepted in the United States
HVAC	Heating, Ventilation and Air-conditioning
KWH	Kilowatt-hours
LOC	Letter of Credit
MISO	Midwest Independent Transmission System Operator, Inc.
MSG	Market Support Generation
MTC	Market Transition Charge
MW	Megawatts
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Council
NJBPU	New Jersey Board of Public Utilities
NOAC	Northwest Ohio Aggregation Coalition
NOV	Notices of Violation
NO_X	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
NUG	Non-Utility Generation
OCC	Ohio Consumers' Counsel
OCI	Other Comprehensive Income
OPAE	Ohio Partners for Affordable Energy
OPEB	Other Post-Employment Benefits
PCAOB	Public Company Accounting Oversight Board (United States)
PCRBs	Pollution Control Revenue Bonds
PJM	PJM Interconnection L.L.C.
PLR	Provider of Last Resort
PPUC	Pennsylvania Public Utility Commission
PRP	Potentially Responsible Party
PSA	Purchase and Sale Agreement
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act
RTC	Regulatory Transition Charge
S&P	Standard & Poor’s Ratings Service
SBC	Societal Benefits Charge
SEC	United States Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
SFAS 71	SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
SFAS 123	SFAS No. 123, "Accounting for Stock-Based Compensation"
SFAS 123(R)	SFAS No. 123 (revised 2004), "Share-Based Payment"
SFAS 131	SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information"
SFAS 133	SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities"
SFAS 140	SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and
	Extinguishment of Liabilities"
SFAS 144	SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"
SFAS 153	SFAS No. 153, "Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29"
SFAS 154	SFAS No. 154, "Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3"
SO₂	Sulfur Dioxide
TBC	Transition Bond Charge
TMI-2	Three Mile Island Unit 2
VIE	Variable Interest Entity

PART I. FINANCIAL INFORMATION

FIRSTENERGY CORP. AND SUBSIDIARIES

OHIO EDISON COMPANY AND SUBSIDIARIES

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES

THE TOLEDO EDISON COMPANY AND SUBSIDIARY

PENNSYLVANIA POWER 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 principal subsidiaries: FENOC, FES and its subsidiary FGCO, FESC, FSG and MYR.

FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, FERC and, as applicable, 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, 2004 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 the first six months of 2005 have been classified as discontinued operations on the Consolidated Statements of Income (see Note 6). As discussed in Note 16, interim period segment reporting in 2004 was reclassified to conform with the current year business segment organizations and operations.

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 11) when it anticipates absorbing a majority of the VIE’s gains or losses. If no entity absorbs a majority of the VIE’s gains or losses, FirstEnergy consolidates a VIE when it expects to receive a majority of the VIE’s residual return. Investments in nonconsolidated affiliates which are not deemed to be VIEs over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control, (20-50 percent 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 Sheet and the percentage share of the entity’s earnings is reported in the Consolidated Statement of Income.

FirstEnergy's and the Companies' independent registered public accounting firm has performed reviews of, and issued reports on, these consolidated interim financial statements in accordance with standards established by the PCAOB. Pursuant to Rule 436(c) under the Securities Act of 1933, their reports of those reviews should not be considered a report within the meaning of Section 7 and 11 of that Act, and the independent registered public accounting firm’s liability under Section 11 does not extend to them.

2 - ACCOUNTING FOR CERTAIN WHOLESALE ENERGY TRANSACTIONS

FES engages in purchase and sale transactions in the PJM Market to support the supply of end-use customers, including PLR requirements in Pennsylvania. In conjunction with FirstEnergy's dedication of its Beaver Valley Plant to PJM on January 1, 2005, FES began accounting for purchase and sale transactions in the PJM Market based on its net hourly position -- recording each hour as either an energy purchase in Fuel and purchased power or energy sale in Unregulated businesses, respectively, in the Consolidated Statements of Income. Hourly energy positions are aggregated to recognize gross purchases and sales for the month.

This revised method of accounting, which has no impact on net income, is consistent with the practice of other energy companies that have dedicated generating capacity to PJM and correlates with PJM's scheduling and reporting of hourly energy transactions. In addition, FES applies this methodology to purchase and sale transactions in MISO's energy market, which became active April 1, 2005.

For periods prior to January 1, 2005, FirstEnergy did not have dedicated generating capacity in PJM and as such, FES recognized purchases and sales in the PJM Market by recording each discrete transaction. Under these transactions, FES would often buy a specific quantity of energy at a certain location in PJM and simultaneously sell a specific quantity of energy at a different location. Physical delivery occurred and the risks and rewards of ownership transferred with each transaction. FES accounted for those transactions on a gross basis in accordance with EITF 99-19.

The FASB's Emerging Issues Task Force is currently considering EITF 04-13, which relates to the accounting for purchases and sales of inventory with the same counterparty. The Task Force will address under what circumstances two or more transactions with the same counterparty should be viewed as a single nonmonetary transaction within the scope of APB 29. At its June 2005 meeting, the Task Force agreed to propose for public comment a framework for evaluating transactions within the scope of EITF 04-13. The proposed framework is based on the principle that two or more transactions with the same counterparty should be viewed as a single transaction when the transactions are entered into in contemplation of one another. If the EITF were to determine that transactions such as FES' purchases and sales in the PJM Market should be accounted for as single nonmonetary transactions, the transition provisions for the EITF may require or permit FES to report the transactions prior to January 1, 2005 on a net basis. This requirement would have no impact on net income, but would reduce both wholesale revenue and purchased power expense by $283 million and $564 million for the three months and six months ended June 30, 2004, respectively.

3 - DEPRECIATION

During the second half of 2004, FirstEnergy engaged an independent third party to assist in reviewing the service lives of its fossil generation units. This study was completed in the first quarter of 2005. As a result of the analysis, FirstEnergy extended the estimated service lives of its fossil generation units for periods ranging from 11 to 33 years during the first quarter of 2005. Extension of the service lives will provide improved matching of depreciation expense with the expected economic lives of those generation units. The change in estimate resulted in increases of $3.1 million (CEI - $1.9 million, OE - $0.6 million, Penn - $0.1 million, TE - $0.3 million, FGCO - $0.2 million) and $9.0 million (CEI - $4.0 million, OE - $3.9 million, Penn - $0.2 million, TE - $0.8 million, FGCO - $0.1 million) in income before discontinued operations and net income ($0.01and $0.03 per share of common stock) during the three and six months ended June 30, 2005, respectively.

4 - EARNINGS PER SHARE

Basic earnings per share are computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share 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. Stock-based awards to purchase shares of common stock totaling 3.3 million in the three months and six months ended June 30, 2004, were excluded from the calculation of diluted earnings per share of common stock because their exercise prices were greater than the average market price of common shares during the period. No stock-based awards were excluded from the calculation in the three months and six months ended June 30, 2005. The following table reconciles the denominators for basic and diluted earnings per share from Income Before Discontinued Operations:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Reconciliation of Basic and Diluted Earnings per Share	2005		2004		2005		2004
	*(In thousands, except per share amounts)*

Income Before Discontinued Operations	$	178,765	$	201,860	$	319,795	$	374,209

Average Shares of Common Stock Outstanding:
Denominator for basic earnings per share
(weighted average shares outstanding)		328,063		327,284		327,986		327,171

Assumed exercise of dilutive stock options and awards		1,816		1,819		1,693		1,890

Denominator for diluted earnings per share		329,879		329,103		329,679		329,061

Income Before Discontinued Operations per Common Share:
Basic		$0.54		$0.61		$0.98		$1.15
Diluted		$0.54		$0.61		$0.97		$1.14

5 - GOODWILL

FirstEnergy's goodwill primarily relates to its regulated services segment. In the three and six months ended June 30, 2005, FirstEnergy adjusted goodwill related to the divestiture of non-core operations (FES' natural gas business, MYR subsidiary, Power Piping Company, and a portion of its interest in FirstCom) as further discussed in Note 6. In addition, the adjustment of the former GPU companies' goodwill was due to the reversal of pre-merger tax reserves as a result of property tax settlements. FirstEnergy estimates that completion of transition cost recovery (see Note 14) will not result in an impairment of goodwill relating to its regulated business segment. A summary of the changes in goodwill for the three months and six months ended June 30, 2005 is shown below.

Three Months Ended	FirstEnergy			CEI		TE		JCP&L		Met-Ed		Penelec
	*(In millions)*

Balance as of April 1, 2005	$	6,034		$	1,694	$	505	$	1,984	$	868	$	887
Non-core asset sales		(1	)		-		-		-		-		-
Balance as of June 30, 2005	$	6,033		$	1,694	$	505	$	1,984	$	868	$	887

Six Months Ended	FirstEnergy			CEI		TE		JCP&L			Met-Ed			Penelec
	*(In millions)*

Balance as of January 1, 2005	$	6,050		$	1,694	$	505	$	1,985		$	870		$	888
Non-core asset sales		(13	)		-		-		-			-			-
Adjustments related to GPU acquisition		(4	)		-		-		(1	)		(2	)		(1	)
Balance as of June 30, 2005	$	6,033		$	1,694	$	505	$	1,984		$	868		$	887

6 - DIVESTITURES AND DISCONTINUED OPERATIONS

In December 2004, FES' natural gas business qualified as assets held for sale in accordance with SFAS 144. On March 31, 2005, FES completed the sale for an after-tax gain of $5 million. In March 2005, FirstEnergy sold 51% of its interest in FirstCom, resulting in an after-tax gain of $4 million. FirstEnergy accounts for its remaining 31.85% interest in FirstCom on the equity basis.

During the first six months of 2005, FirstEnergy sold certain of its FSG subsidiaries, Elliott-Lewis, Spectrum and Cranston, and MYR’s Power Piping Company subsidiary, resulting in an after-tax gain of $12 million. FSG's remaining subsidiaries qualify as assets held for sale in accordance with SFAS 144 and are expected to be recognized as completed sales before the end of 2005. The assets and liabilities of these remaining FSG subsidiaries are not material to FirstEnergy’s Consolidated Balance Sheet as of June 30, 2005, and therefore have not been separately classified as assets held for sale.

Net results (including the gains on sales of assets discussed above) for Elliott-Lewis, Cranston, Power Piping and FES' natural gas business of $(1) million and $18 million for the three and six months ended June 30, 2005, respectively, and $2 million and $4 million for the three and six months ended June 30, 2004, respectively, are reported as discontinued operations on FirstEnergy's Consolidated Statements of Income. Pre-tax operating results for these entities were $(2) million and $2 million for the three and six months ended June 30, 2005, respectively, and $4 million and $7 million for the three and six months ended June 30, 2004, respectively. Revenues associated with discontinued operations for the three and six months ended June 30, 2005 were $11 million and $206 million, respectively, and for the three and six months ended June 30, 2004 were $158 million and $357 million, respectively. As of June 30, 2005, the remaining FSG businesses do not meet the criteria for discontinued operations; therefore, the net results ($(3) million and $(4) million for the three and six months ended June 30, 2005, respectively, and $0.3 million and $(1) million for the three and six months ended June 30, 2004, respectively) from these subsidiaries have been included in continuing operations. See Note 16 for FSG's segment financial information.

The following table summarizes the sources of income (loss) from discontinued operations.

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2005			2004		2005		2004
	*(In millions)*
Discontinued operations (net of tax)
Gain on sale:
Natural gas business	$	-		$	-	$	5	$	-
FSG and MYR subsidiaries		-			-		12		-
Reclassification of operating income		(1	)		2		1		4
Total	$	(1	)	$	2	$	18	$	4

7 - 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 non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes, and to a lesser extent, for trading purposes. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughout the Company.

FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheet at their fair value unless they meet the normal purchase and normal sales criteria. The changes in the fair value of a derivative instrument are recorded in current earnings, in other comprehensive income, or as part of the value of the hedged item depending on whether or not it is designated as part of a hedge transaction and on the nature of the hedge transaction.

FirstEnergy has entered into 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 second quarter, FirstEnergy unwound swaps with a total notional amount of $350 million from which it received $17 million in cash gains. The gains will be recognized over the remaining maturity of each respective hedged security as reduced interest expense. As of June 30, 2005, the aggregate notional value of interest rate swap agreements outstanding was $1.4 billion.

FirstEnergy engages in hedging of 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 impact of ineffectiveness on earnings during the three and six months ended June 30, 2005 was not material. The net deferred loss of $93 million included in AOCL as of June 30, 2005, for derivative hedging activity, as compared to the December 31, 2004 balance of $92 million of net deferred losses, resulted from a $4 million increase related to current hedging activity, a $4 million increase due to the sale of gas business contracts and a $7 million decrease due to net hedge losses included in earnings during the six months ended June 30, 2005. Approximately $16 million of the net deferred loss on derivative instruments in AOCL as of June 30, 2005 is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments will fluctuate from period to period based on various market factors.

FirstEnergy engages in the trading of commodity derivatives and periodically experiences net open positions. FirstEnergy’s risk management policies limit the exposure to market risk from open positions and require daily reporting to management of potential financial exposures. During the three and six months ended June 30, 2005, the effect of discretionary trading on earnings was not material.

8 - STOCK BASED COMPENSATION

FirstEnergy applies the recognition and measurement principles of APB 25 and related interpretations in accounting for its stock-based compensation plans. No material stock-based employee compensation expense is reflected in net income for options as all options granted under those plans have exercise prices equal to the market value of the underlying common stock on the respective grant dates, resulting in substantially no intrinsic value.

In December 2004, the FASB issued SFAS 123(R), a revision to SFAS 123 which requires expensing the fair value of stock options (see Note 15). In April 2005, the SEC delayed the effective date of SFAS 123(R) to annual, rather than interim, periods that begin after June 15, 2005. FirstEnergy will be required to adopt this standard beginning January 1, 2006. The table below summarizes the effects on FirstEnergy’s net income and earnings per share had FirstEnergy applied the fair value recognition provisions of SFAS 123(R) to stock-based employee compensation in the current reporting periods.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	*(In thousands, except per share amounts)*

Net income, as reported	$	177,992		$	204,045		$	337,718		$	378,044

Add back compensation expense
reported in net income, net of tax
(based on APB 25)*		14,413			9,112			22,381			15,806

Deduct compensation expense based
upon estimated fair value, net of tax		(15,656	)		(13,882	)		(26,493	)		(24,829	)

Pro forma Net income	$	176,749		$	199,275		$	333,606		$	369,021

Earnings Per Share of Common Stock -
Basic
As reported		$0.54			$0.62			$1.03			$1.16
Pro forma		$0.54			$0.61			$1.02			$1.13
Diluted
As reported		$0.54			$0.62			$1.02			$1.15
Pro forma		$0.54			$0.61			$1.01			$1.12

* Includes restricted stock, restricted stock units, stock options, performance shares, Employee Stock Ownership Plan, Executive Deferred Compensation Plan and Deferred Compensation Plan for Outside Directors.

FirstEnergy reduced the use of stock options and increased the use of performance-based, restricted stock units. Therefore, the pro forma effects of applying SFAS 123(R) may not be representative of its future effect. FirstEnergy does not expect to accelerate out-of-the-money options in anticipation of implementing SFAS 123(R) on January 1, 2006 (see Note 15).

9 - ASSET RETIREMENT OBLIGATIONS

FirstEnergy has identified applicable legal obligations for nuclear power plant decommissioning, reclamation of a sludge disposal pond related to the Bruce Mansfield Plant and closure of two coal ash disposal sites. The ARO liability of $1.1 billion as of June 30, 2005 included $1.1 billion for nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. The Companies' share of the obligation to decommission these units was developed based on site specific studies performed by an independent engineer. FirstEnergy utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.

The Companies maintain nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of June 30, 2005, the fair value of the decommissioning trust assets was $1.6 billion.

The following tables provide the beginning and ending aggregate carrying amount of the ARO and the changes to the balance during the three and six months ended June 30, 2005 and 2004, respectively.

Three Months Ended	FirstEnergy		OE		CEI		TE		Penn		JCP&L		Met-Ed		Penelec
	*(In millions)*
ARO Reconciliation
Balance, April 1, 2005	$	1,095	$	204	$	276	$	198	$	141	$	74	$	135	$	67
Liabilities incurred		-		-		-		-		-		-		-		-
Liabilities settled		-		-		-		-		-		-		-		-
Accretion		18		4		5		3		2		1		2		1
Revisions in estimated
cash flows		-		-		-		-		-		-		-		-
Balance June 30, 2005	$	1,113	$	208	$	281	$	201	$	143	$	75	$	137	$	68

Balance, April 1, 2004	$	1,198	$	191	$	259	$	185	$	132	$	111	$	213	$	107
Liabilities incurred		-		-		-		-		-		-		-		-
Liabilities settled		-		-		-		-		-		-		-		-
Accretion		19		3		4		3		2		2		3		2
Revisions in estimated
cash flows		-		-		-		-		-		-		-		-
Balance June 30, 2004	$	1,217	$	194	$	263	$	188	$	134	$	113	$	216	$	109

Six Months Ended	FirstEnergy		OE		CEI		TE		Penn		JCP&L		Met-Ed		Penelec
	*(In millions)*
ARO Reconciliation
Balance, January 1, 2005	$	1,078	$	201	$	272	$	195	$	138	$	72	$	133	$	67
Liabilities incurred		-		-		-		-		-		-		-		-
Liabilities settled		-		-		-		-		-		-		-		-
Accretion		35		7		9		6		5		3		4		1
Revisions in estimated
cash flows		-		-		-		-		-		-		-		-
Balance June 30, 2005	$	1,113	$	208	$	281	$	201	$	143	$	75	$	137	$	68

Balance, January 1, 2004	$	1,179	$	188	$	255	$	182	$	130	$	109	$	210	$	105
Liabilities incurred		-		-		-		-		-		-		-		-
Liabilities settled		-		-		-		-		-		-		-		-
Accretion		38		6		8		6		4		4		6		4
Revisions in estimated
cash flows		-		-		-		-		-		-		-		-
Balance June 30, 2004	$	1,217	$	194	$	263	$	188	$	134	$	113	$	216	$	109

10 - PENSION AND OTHER POSTRETIREMENT BENEFITS:

The components of FirstEnergy's net periodic pension cost and other postretirement benefit cost (including amounts capitalized) for the three and six months ended June 30, 2005 and 2004, consisted of the following:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Pension Benefits	2005			2004			2005			2004
	*(In millions)*

Service cost	$	19		$	19		$	38		$	39
Interest cost		64			63			128			126
Expected return on plan assets		(86	)		(71	)		(173	)		(143	)
Amortization of prior service cost		2			2			4			4
Recognized net actuarial loss		9			10			18			20
Net periodic cost	$	8		$	23		$	15		$	46

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Other Postretirement Benefits	2005			2004			2005			2004
	*(In millions)*
Service cost	$	10		$	8		$	20		$	19
Interest cost		27			25			55			56
Expected return on plan assets		(11	)		(10	)		(22	)		(22	)
Amortization of prior service cost		(11	)		(8	)		(22	)		(19	)
Recognized net actuarial loss		10			9			20			20
Net periodic cost	$	25		$	24		$	51		$	54

Pension and postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. The Companies capitalize employee benefits related to construction projects. The net periodic pension costs (credits) and net periodic postretirement benefit costs (including amounts capitalized) recognized by each of the Companies in the three and six months ended June 30, 2005 and 2004 were as follows:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
Pension Benefit Cost (Credit)	2005			2004		2005			2004
	*(In millions)*

OE	$	0.2		$	1.8	$	0.4		$	3.5
Penn		(0.2	)		0.1		(0.4	)		0.2
CEI		0.3			1.6		0.7			3.2
TE		0.3			0.8		0.6			1.6
JCP&L		(0.3	)		1.9		(0.5	)		3.7
Met-Ed		(1.1	)		-		(2.2	)		0.1
Penelec		(1.3	)		0.1		(2.7	)		0.2

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Other Postretirement Benefit Cost	2005		2004		2005		2004
	*(In millions)*

OE	$	5.8	$	4.9	$	11.5	$	12.0
Penn		1.2		1.0		2.4		2.5
CEI		3.8		3.6		7.6		9.2
TE		2.2		1.3		4.3		3.4
JCP&L		1.5		0.9		4.2		2.5
Met-Ed		0.4		0.5		0.8		1.8
Penelec		2.0		0.4		4.0		1.8

11 - VARIABLE INTEREST ENTITIES

Leases

Included in FirstEnergy’s consolidated financial statements are PNBV and Shippingport, two 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 three-percent equity interest by a nonaffiliated third party and a three-percent 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 $1 billion, 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 $663 million, $101 million and $531 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 structured 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 nine 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 nine 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 nine 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. The maximum exposure to loss from these entities results from increases in the variable pricing component under the contract terms and cannot be determined without the requested data. Purchased power costs from these entities during the three and six months ended June 30, 2005 and 2004 are shown in the table below:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2005		2004		2005		2004
	*(In millions)*

JCP&L	$	29	$	35	$	56	$	63
Met-Ed		14		9		30		25
Penelec		7		6		14		13
Total	$	50	$	50	$	100	$	101

Securitized Transition Bonds

The consolidated financial statements of FirstEnergy and JCP&L include the results of JCP&L Transition, a wholly owned limited liability company of JCP&L. In June 2002, JCP&L Transition 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.

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. The transition bonds are obligations of JCP&L Transition only and are collateralized solely by the equity and assets of JCP&L Transition, which consist primarily of bondable transition property. The bondable transition property is solely the property of JCP&L Transition.

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 the transition bonds and other fees and expenses associated with their issuance. JCP&L sold the bondable transition property to JCP&L Transition and, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to a servicing agreement with JCP&L Transition. JCP&L is entitled to a quarterly servicing fee of $100,000 that is payable from TBC collections.

12 - OHIO TAX LEGISLATION

On June 30, 2005, the State of Ohio enacted new tax legislation that creates a new Commercial Activity Tax (CAT), which is based on qualifying "taxable gross receipts" and will not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax is effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and the personal property tax is phased-out over a four-year period at a rate of approximately 25% annually, beginning with the year ended 2005. For example, during the phase-out period the Ohio income-based franchise tax will be computed consistently with the prior tax law, except that the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period. As a result of the new tax structure, all net deferred tax benefits that are not expected to reverse during the five-year phase-in period were written-off as of June 30, 2005.

The increase to income taxes associated with the adjustment to net deferred taxes for the three and six months ended June 30, 2005 is summarized below (in millions):


OE	$	36.0
CEI		7.5
TE		17.5
Other FirstEnergy subsidiaries		10.7
Total FirstEnergy	$	71.7

Income tax expenses were reduced during the three and six months ended June 30, 2005 by the initial phase-out of the Ohio income-based franchise tax as summarized below (in millions):

OE	$	4.9
CEI		1.4
TE		0.5
Other FirstEnergy subsidiaries		0.8
Total FirstEnergy	$	7.6

13 - 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. Such agreements include contract guarantees, surety bonds and ratings contingent collateralization provisions. As of June 30, 2005, outstanding guarantees and other assurances aggregated approximately $2.4 billion and included contract guarantees ($1.1 billion), surety bonds ($0.3 billion) and LOCs ($1.0 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 subsidiary financing principally for 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. Such parental guarantees amount to $0.9 billion (included in the $1.1 billion discussed above) as of June 30, 2005 and the likelihood is remote that such guarantees will increase amounts otherwise to be paid by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related contracts.

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 a LOC may be required of the subsidiary. The following table summarizes collateral provisions in effect as of June 30, 2005:

	Total		Collateral Paid				Remaining
Collateral Provisions	Exposure		Cash		LOC		Exposure
	*(In millions)*

Credit rating downgrade	$	367	$	141	$	18	$	208
Adverse event		50		-		7		43
Total	$	417	$	141	$	25	$	251

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $296 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. 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 following table includes information regarding the subsidiary companies and their respective financing arrangement.

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

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 ($47 million as of June 30, 2005), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.

(B) ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. The effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position. These environmental regulations affect 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. Overall, FirstEnergy believes it is in compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such changes would be. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $430 million for 2005 through 2007.

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

FirstEnergy plans to issue a report that will disclose the Companies’ environmental activities, including their plans to respond to environmental requirements. FirstEnergy expects to complete the report by December 1, 2005 and will post the report on its web site, www.firstenergycorp.com.

Clean Air Act Compliance

The Companies are required to meet federally approved SO₂ 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. The Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

The Companies believe they are complying 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 from the Companies' facilities. The EPA's NO_x Transport Rule imposes uniform reductions of NO_x emissions (an approximate 85 percent 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. The Companies believe their facilities are also complying with the NO_x budgets established under State Implementation Plans through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" 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 nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR will require 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). The Companies’ Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to the caps on SO₂ and NO_x emissions, whereas our New Jersey fossil-fired generation facilities will be subject to a cap on NO_x emissions only. 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 the Companies operate 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. On March 14, 2005, the EPA finalized a cap-and-trade program to reduce mercury emissions in two phases from coal-fired power plants. Initially, mercury emissions will decline by 2010 as a "co-benefit" from implementation of SO₂ and NO_xemission 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. The future cost of compliance with these regulations may be substantial.

W. H. Sammis Plant

In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities covering 44 power plants, including the W. H. Sammis Plant, which is owned by OE and Penn. In addition, the U.S. Department of Justice (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 New Source Review cases. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. 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 W. H. Sammis Plant New Source Review litigation. This settlement agreement, which is in the form of a Consent Decree that was approved by the Court on July 11, 2005, requires OE and Penn to reduce emissions from the W. H. Sammis Plant and other plants through the installation of pollution control devices requiring capital expenditures currently estimated to be $1.1 billion (primarily in the 2008 to 2011 time period). The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy purchase power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 included the penalties payable by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized liabilities of $9.2 million and $0.8 million, respectively, for probable future cash contributions toward environmentally beneficial projects during the first quarter of 2005.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made greenhouse gases emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic greenhouse gas intensity - the ratio of emissions to economic output - by 18 percent through 2012.

The Companies cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO₂ emissions could require significant capital and other expenditures. However, the CO₂ emissions per kilowatt-hour of electricity generated by the Companies is lower than many regional competitors due to the Companies' 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 the Companies' plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to the Companies' 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 species are drawn into a facility's cooling water system. The Companies are conducting comprehensive demonstration studies, due in 2008, to determine the operational measures, equipment or restoration activities, if any, necessary for compliance by their facilities with the performance standards. FirstEnergy is unable to predict the outcome of such studies. Depending on the outcome of such studies, 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.

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, 2005, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other nonaffiliated 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. Included in Current Liabilities and Other Noncurrent Liabilities are accrued liabilities aggregating approximately $64 million (JCP&L - $46.8 million, CEI - $2.3 million, TE - $0.2 million, Met-Ed - $47,000 and other - $15.0 million) as of June 30, 2005.

(C) OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation

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

In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision 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, New Jersey. On September 8, 2004, the New Jersey Supreme Court denied the motions filed by plaintiffs and JCP&L for leave to appeal the decision of the Appellate Division. JCP&L has filed a motion for summary judgment. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of June 30, 2005.

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 concludes, 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 website (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 also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability 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, and therefore FirstEnergy has not accrued a liability as of June 30, 2005 for any expenditures in excess of those actually incurred through that date. 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. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

Three substantially similar actions were filed in various Ohio State courts by plaintiffs seeking to represent customers who allegedly suffered damages as a result of the August 14, 2003 power outages. All three cases were dismissed for lack of jurisdiction and further appeals were unsuccessful. Two of these cases were refiled at the PUCO, one in 2004 and another in 2005. In each, individual complainants—three in one case and four in the other—seek damages related to the outages and also seek to represent others as part of a class action. FirstEnergy has filed responsive pleadings to both cases. The PUCO has dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Both cases are otherwise currently pending further proceedings. In addition to the two cases that were refiled at the PUCO, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages.

One complaint was filed on August 25, 2004 against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy filed a motion to dismiss with the Court on October 22, 2004. No timetable for a decision on the motion to dismiss has been established by the Court. No damage estimate has been provided and thus potential liability has not been determined.

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. In particular, 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 and results of operations.

Nuclear Plant Matters

FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station. On December 10, 2004, FirstEnergy received a letter from the United States Attorney's Office stating that FENOC is a target of the federal grand jury investigation into alleged false statements made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. On February 10, 2005, FENOC received an additional subpoena for documents related to root cause reports regarding reactor head degradation and the assessment of reactor head management issues at Davis-Besse. On May 11, 2005, FENOC received a subpoena for documents related to outside meetings attended by Davis-Besse personnel on corrosion and cracking of control rod drive mechanisms and additional root cause evaluations.

On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head described above. On July 8, 2005, FENOC requested an additional 120 days to respond to the NOV. FirstEnergy accrued $2.0 million for the proposed fine in 2004 and accrued the remaining liability for the proposed fine during the first quarter of 2005.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability based on the events surrounding Davis-Besse, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.

Effective July 1, 2005, the NRC oversight panel for Davis-Besse was terminated and Davis-Besse returned to the standard NRC reactor oversight process. At that time, NRC inspections were augmented to include inspections to support the NRC's Confirmatory Order dated March 8, 2004 that was issued at the time of startup and to address an NRC White Finding related to the performance of the emergency sirens.

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. FENOC operates the Perry Nuclear Power Plant, which is currently owned and/or leased by OE, CEI, TE and Penn (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which will include owned portions of the plant). On April 4, 2005, the NRC held a public forum 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 Plant operated "in a manner that preserved public health and safety" and met all cornerstone objectives although it remained under the heightened NRC oversight since August 2004. During the public forum and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process, from increased oversight to possible impact to the plant’s operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition.

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 most significant not otherwise discussed above are described below.

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.

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 and results of operations.

14 - REGULATORY MATTERS:

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, 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. Finally, the PUCO is continuing to review the FirstEnergy filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

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. On March 29, 2004, the NJBPU adopted a Memorandum of Understanding (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 a Special Reliability Master 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 (Focused Audit). A final order in the Focused Audit docket was issued by the NJBPU on July 23, 2004. On February 11, 2005, JCP&L met with the Ratepayer Advocate to discuss reliability improvements. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.

In May 2004, the PPUC issued an order approving revised reliability benchmarks and standards, including revised benchmarks and standards for Met-Ed, Penelec and Penn. Met-Ed, Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004, due to their implementation of automated outage management systems following restructuring. Evidentiary hearings have been scheduled for November 2005. FirstEnergy is unable to predict the outcome of this proceeding.

In November 2004, the PPUC approved a settlement agreement filed by Met-Ed, Penelec and Penn that addressed issues related to a PPUC investigation into Met-Ed's, Penelec's and Penn's service reliability performance. As part of the settlement, Met-Ed, Penelec and Penn agreed to enhance service reliability, ongoing periodic performance reporting and communications with customers, and to collectively maintain their current spending levels of at least $255 million annually on combined capital and operation and maintenance expenditures for transmission and distribution for the years 2005 through 2007. The settlement also outlines an expedited remediation process to address any alleged non-compliance with terms of the settlement and an expedited PPUC hearing process if remediation is unsuccessful.

Ohio

On August 5, 2004, the Ohio Companies accepted the Rate Stabilization Plan as modified and approved by the PUCO on August 4, 2004, subject to a competitive bid process. The Rate Stabilization Plan was filed by the Ohio Companies to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. In the second quarter of 2004, the Ohio Companies implemented the accounting modifications related to the extended amortization periods and interest costs deferral on the deferred customer shopping incentive balances. On October 1 and October 4, 2004, the OCC and NOAC, respectively, filed appeals with the Supreme Court of Ohio to overturn the June 9, 2004 PUCO order and associated entries on rehearing.

The Rate Stabilization Plan extends current generation prices through 2008, ensuring adequate generation supply at stabilized prices, and continues the Ohio Companies' support of energy efficiency and economic development efforts. Other key components of the Rate Stabilization Plan include the following:

Amortization period for transition costs being recovered through the RTC extends for OE to as late as 2007; CEI to as late as mid-2009 and TE to as late as mid-2008;

Deferral of interest costs on the accumulated customer shopping incentives as new regulatory assets; and

Ability to request increases in generation charges during 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes.

On May 27, 2005, the Ohio Companies filed an application with the PUCO to establish a generation rate adjustment rider under the Rate Stabilization Plan. The application seeks to implement recovery of increased fuel costs from 2006 through 2008 applicable to the Ohio Companies' retail customers through a tariff rider to be implemented January 1, 2006. The application reflects projected increases in fuel costs in 2006 compared to 2002 baseline costs. The new rider is seeking to recover all costs above the baseline (approximately $93 million in 2006). Various parties including the OCC have intervened in this case. The Ohio Companies have received discovery requests from the OCC and the PUCO staff. A procedural schedule has been established by the PUCO, with a hearing scheduled for October 4, 2005.

On December 9, 2004, the PUCO rejected the auction price results from a required competitive bid process and issued an entry stating that the pricing under the approved Rate Stabilization Plan will take effect on January 1, 2006. The PUCO may require the Ohio Companies to undertake, no more often than annually, a similar competitive bid process to secure generation for the years 2007 and 2008. On July 22, 2005, FirstEnergy filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approved by the PUCO for the Ohio Companies in 2004. Any acceptance of future competitive bid results would terminate the Rate Stabilization Plan pricing, but not the related approved accounting, and not until twelve months after the PUCO authorizes such termination.

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 MTC rates. As of June 30, 2005, the accumulated deferred cost balance totaled approximately $518 million. New Jersey law allows for securitization of JCP&L's deferred balance upon application by JCP&L and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. On February 14, 2003, JCP&L filed for approval of the securitization of the deferred balance. JCP&L is in discussions with the NJBPU staff as a result of the stipulated settlement agreements (as further discussed below) which recommended that the NJBPU issue an order regarding JCP&L's application.

The 2003 NJBPU decision on JCP&L's base electric rate proceeding disallowed certain regulatory assets and provided for an interim return on equity of 9.5% on JCP&L's rate base. The decision ordered a Phase II proceeding in which the NJBPU would review whether JCP&L is in compliance with current service reliability and quality standards and determine whether the expenditures and projects undertaken by JCP&L to increase its system's reliability are prudent and reasonable for rate recovery. Depending on its assessment of JCP&L's service reliability, the NJBPU could have increased JCP&L’s return on equity to 9.75% or decreased it to 9.25%. On August 15, 2003 and June 1, 2004, JCP&L filed with the NJBPU an interim motion and a supplemental and amended motion for rehearing and reconsideration of the 2003 NJBPU decision, respectively. On July 7, 2004, the NJBPU granted limited reconsideration and rehearing on the following issues: (1) deferred cost disallowances; (2) the capital structure including the rate of return; (3) merger savings, including amortization of costs to achieve merger savings; and (4) decommissioning costs.

On July 16, 2004, JCP&L filed the Phase II petition and testimony with the NJBPU, requesting an increase in base rates of $36 million for the recovery of system reliability costs and a 9.75% return on equity. The filing also requested an increase to the MTC deferred balance recovery of approximately $20 million annually.

On May 25, 2005, the NJBPU approved two stipulated settlement agreements. The first stipulation between JCP&L and the NJBPU staff resolves all of the issues associated with JCP&L's motion for reconsideration of the 2003 NJBPU order (Phase I Order). The second stipulation between JCP&L, the NJBPU staff and the Ratepayer Advocate resolves all of the issues associated with JCP&L's Phase II proceeding. The stipulated settlements provide for, among other things, the following:

An annual increase in distribution revenues of $23 million effective June 1, 2005, associated with the Phase I Order reconsideration;

An annual increase in distribution revenues of $36 million effective June 1, 2005, related to JCP&L's Phase II Petition;

An annual reduction in both rates and amortization expense of $8 million, effective June 1, 2005, in anticipation of an NJBPU order regarding JCP&L's request to securitize up to $277 million of its deferred cost balance;

An increase in JCP&L's authorized return on common equity from 9.5% to 9.75%; and

A commitment by JCP&L to maintain a target level of customer service reliability with a reduction in JCP&L's authorized return on common equity to its previous level of 9.5% after the target is not met for two consecutive quarters. The authorized return on common equity would then be restored to 9.75% when the target is met for two consecutive quarters.

The Phase II stipulation included an agreement that the distribution revenues increase reflects a three-year amortization of JCP&L's service reliability improvement costs incurred in 2003-2005. This resulted in the creation of a regulatory asset associated with the accelerated tree trimming costs which were expensed in 2003 and 2004. The establishment of the new regulatory asset of approximately $28 million resulted in an increase to net income of approximately $16 million ($0.05 per share of common stock) in the second quarter of 2005.

JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balance with the exception of 300 MW from JCP&L's NUG committed supply currently being used to serve BGS customers pursuant to NJBPU order. New BGS tariffs reflecting the results of a February 2005 auction for the BGS supply became effective June 1, 2005. On May 5, 2005, the NJBPU issued an order that BGS procurement proposals for post transition year four be filed by July 1, 2005. The NJBPU requested that the filings address transmission rate issues and rate design alternatives. JCP&L filed its proposal on July 1, 2005. The auction is scheduled to take place in February 2006 for the supply period beginning June 1, 2006.

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 Ratepayer Advocate filed comments on February 28, 2005. On March 18, 2005, JCP&L filed a response to those comments. A schedule for further proceedings has not yet been set.

Pennsylvania

A February 2002 Commonwealth Court of Pennsylvania decision affirmed the June 2001 PPUC decision regarding approval of the FirstEnergy/GPU merger, remanded the issues of quantification and allocation of merger savings to the PPUC and denied Met-Ed and Penelec the rate relief initially approved in the PPUC decision. On October 2, 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC’s June 2001 order in its entirety. In accordance with the PPUC's direction, Met-Ed and Penelec filed supplements to their tariffs that were effective October 2003 and that reflected the CTC rates and shopping credits in effect prior to the June 2001 order.

In accordance with PPUC directives, Met-Ed and Penelec have been negotiating with interested parties in an attempt to resolve the merger savings issues that are the subject of remand from the Commonwealth Court. Met-Ed’s and Penelec’s combined portion of total merger savings is estimated to be approximately $31.5 million. On April 13, 2005, the Commonwealth Court issued an interim order in the remand proceeding that the parties should report the status of the negotiations to the PPUC with a copy to the ALJ. The parties exchanged settlement proposals in May and June 2005 and continue to have settlement discussions.

In an October 16, 2003 order, the PPUC approved June 30, 2004 as the date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC order also denied their accounting treatment request regarding the CTC rate/shopping credit swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. On October 22, 2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking that the Court reverse this PPUC finding; a Commonwealth Court judge subsequently denied their Objection on October 27, 2003 without explanation. On October 31, 2003, Met-Ed and Penelec filed an Application for Clarification of the Court order with the judge, a Petition for Review of the PPUC's October 2 and October 16 Orders, and an application for reargument, if the judge, in his clarification order, indicates that Met-Ed's and Penelec's Objection was intended to be denied on the merits. The Reargument Brief before the Commonwealth Court was filed on January 28, 2005.

Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sales agreement. The PLR sale is automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES retains 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 under their NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR energy costs during the term of the agreement with FES. Met-Ed and Penelec are authorized to defer differences between NUG contract costs and current market prices.

Transmission

On November 1, 2004, ATSI requested authority from the FERC to defer approximately $54 million of vegetation management costs ($17 million deferred as of June 30, 2005) estimated to be incurred from 2004 through 2007. On March 4, 2005, the FERC approved ATSI's request to defer those costs. ATSI expects to file an application with FERC in the first quarter of 2006 for recovery of the deferred costs.

On December 30, 2004, the Ohio Companies filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application seeks recovery of these costs beginning January 1, 2006. At the time of filing the application, these costs were estimated to be approximately $30 million per year; however, the Ohio Companies anticipate that this amount will increase. The Ohio Companies requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted thereafter each July 1. The Ohio Companies reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only other party in this proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This settlement, which was filed with the PUCO on July 22, 2005, provides for the rider recovery requested by the Ohio Companies, with carrying charges applied in the subsequent year’s rider for any over or under collection while the then-current rider is in effect. If the settlement stipulation is approved by the PUCO, the actual amounts to be recovered through the January 1, 2006 rider will be submitted to the PUCO on or before November 1, 2005.

The second application seeks authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for the Ohio Companies to defer incremental transmission and ancillary service-related charges incurred as a participant in the MISO, but only for those costs incurred during the period December 30, 2004, through December 31, 2005. Deferral of all costs incurred prior to December 31, 2004 was denied. The PUCO also authorized the Ohio Companies to accrue carrying charges on the deferred balances. An application filed with the PUCO to recover these deferred charges over a five-year period through the rider, beginning in 2006, is pending. The OCC, OPAE and the Ohio Companies each filed applications for rehearing. The Ohio Companies sought authority to defer the transmission and ancillary service related costs incurred during the period October 1, 2003 through December 29, 2004, while both OCC and OPAE sought to have the PUCO deny deferral of all costs. On July 6, 2005, the PUCO denied the Ohio Companies and OCC’s applications and, at the request of the Ohio Companies, struck as untimely OPAE’s application. The Ohio Companies and the OCC have sixty days from that date to file a notice of appeal with the Ohio Supreme Court.

On January 12, 2005, Met-Ed and Penelec filed a request with the PPUC for deferral of transmission-related costs beginning January 1, 2005, estimated to be approximately $8 million per month.

Various parties have intervened in each of the cases above, and the Companies have not yet implemented deferral accounting for these costs.

On September 16, 2004, the FERC issued an order that imposed additional obligations on CEI under certain pre-Open Access transmission contracts among CEI and the cities of Cleveland and Painesville, Ohio. Under the FERC's original decision, CEI would have been responsible for a portion of new energy market charges imposed by MISO when its energy markets began in the spring of 2005. CEI filed for rehearing of the order from the FERC on October 18, 2004. On April 15, 2005, the FERC issued an order on rehearing that "carves out" these contracts from the MISO Day 2 market, which became effecitve April 1, 2005. While the order on rehearing is favorable to CEI, the impact of the FERC decision on CEI is dependent upon many factors, including the arrangements made by the cities for transmission service and MISO's ability to administer the contracts. Accordingly, the impact of this decision cannot be determined at this time.

On January 31, 2005, certain PJM transmission owners made three filings 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. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On June 30, 2005, the PJM transmission owners filed a request for rehearing of the May 31, 2005 order.

Regulatory Assets

The EUOC recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered from customers under the Companies' respective transition and regulatory plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those operations.

The Ohio Companies are deferring customer shopping incentives and interest costs as new regulatory assets in accordance with the transition and rate stabilization plans. These regulatory assets (OE - $274 million, CEI - $354 million, TE - $108 million, as of June 30, 2005) will be recovered through a surcharge rate equal to the RTC rate in effect when the transition costs have been fully recovered. Recovery of the new regulatory assets will begin at that time and amortization of the regulatory assets for each accounting period will be equal to the surcharge revenue recognized during that period. OE, TE and CEI expect to recover these deferred customer shopping incentives by August 31, 2008, September 30, 2008 and August 31, 2010, respectively.

Regulatory transition costs as of June 30, 2005 for JCP&L, Met-Ed and Penelec are approximately $2.2 billion, $0.7 billion and $0.1 billion, respectively. Deferral of above-market costs from power supplied by NUGs to JCP&L are approximately $1.1 billion and are being recovered through BGS and MTC revenues. Met-Ed and Penelec have deferred above-market NUG costs totaling approximately $0.5 billion and $0.1 billion, respectively. These costs are being recovered through CTC revenues. The regulatory asset for above-market NUG costs and the corresponding liability are adjusted to fair value at the end of each quarter. Recovery of the remaining regulatory transition costs is expected to continue under the provisions of the various regulatory proceedings in New Jersey and Pennsylvania.

15 - NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

SFAS 154 - "Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3"

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in the Consolidated Statements of Income. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. FirstEnergy and the Companies will adopt this Statement effective January 1, 2006.

FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective no later than the end of fiscal years ending after December 15, 2005. Therefore, FirstEnergy will adopt this Interpretation in the fourth quarter of 2005. FirstEnergy and the Companies are currently evaluating the effect this Interpretation will have on their financial statements.

SFAS 153, "Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29"

In December 2004, the FASB issued SFAS 153 amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective for nonmonetary exchanges occurring in fiscal periods beginning after June 15, 2005 and are to be applied prospectively. As a result, FirstEnergy will adopt this Statement effective January 1, 2006, and does not expect it to have a material impact on its financial statements.

SFAS 123(R), "Share-Based Payment"

In December 2004, the FASB issued SFAS 123(R), a revision to SFAS 123, which requires expensing stock options in the financial statements. Important to applying the new standard is understanding how to (1) measure the fair value of stock-based compensation awards and (2) recognize the related compensation cost for those awards. For an award to qualify for equity classification, it must meet certain criteria in SFAS 123(R). An award that does not meet those criteria will be classified as a liability and remeasured each period. SFAS 123(R) retains SFAS 123's requirements on accounting for income tax effects of stock-based compensation. In April 2005, the SEC delayed the effective date of SFAS 123(R) to annual, rather than interim, periods that begin after June 15, 2005. The SEC’s new rule results in a six-month deferral for companies with a fiscal year beginning January 1. Therefore, FirstEnergy will adopt this Statement effective January 1, 2006. The Company will be applying modified prospective application, without restatement of prior interim periods. Any potential cumulative adjustments have not been determined. FirstEnergy uses the Black-Scholes option-pricing model to value options and will continue to do so upon adoption of SFAS 123(R).

SFAS 151, "Inventory Costs - an amendment of ARB No. 43, Chapter 4"

In November 2004, the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be "so abnormal" that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by FirstEnergy beginning January 1, 2006. FirstEnergy is currently evaluating this Standard and does not expect it to have a material impact on the financial statements.

EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In March 2004, the EITF reached a consensus on the application guidance for Issue 03-1. EITF 03-1 provides a model for determining when investments in certain debt and equity securities are considered other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair value and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective for periods beginning after June 15, 2004, were delayed indefinitely by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy continues to evaluate its investments as required by existing authoritative guidance.

FSP 109-1, "Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction and Qualified Production Activities Provided by the American Jobs Creation Act of 2004"

Issued in December 2004, FSP 109-1 provides guidance related to the provision within the American Jobs Creation Act of 2004 (Act) that provides a tax deduction on qualified production activities. The Act includes a tax deduction of up to nine percent (when fully phased-in) of the lesser of (a) "qualified production activities income," as defined in the Act, or (b) taxable income (after the deduction for the utilization of any net operating loss carryforwards). This tax deduction is limited to 50 percent of W-2 wages paid by the taxpayer. The FASB believes that the deduction should be accounted for as a special deduction in accordance with SFAS 109, "Accounting for Income Taxes." FirstEnergy is currently evaluating this FSP and does not expect it to have a material impact on the Company's financial statements.

16 - SEGMENT INFORMATION:

FirstEnergy has three reportable segments: regulated services, power supply management services and facilities (HVAC) services. The aggregate "Other" segments do not individually meet the criteria to be considered a reportable segment. FirstEnergy's primary segment is its regulated services segment, whose operations include the regulated sale of electricity and distribution and transmission services by its eight EUOCs in Ohio, Pennsylvania and New Jersey. The power supply management services segment primarily consists of the subsidiaries (FES, FGCO and FENOC) that sell electricity in deregulated markets and operate the generation facilities of OE, CEI, TE and Penn resulting from the deregulation of the Companies' electric generation business. "Other" consists of MYR (a construction service company), natural gas operations (recently sold - see Note 6) and telecommunications services. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as "reportable segments."

The regulated services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems. Its revenues are primarily derived from electricity delivery and transition cost recovery. Assets of the regulated services segment include generating units that are leased to the power supply management services. The regulated services segment’s internal revenues represent the rental revenues for the generating unit leases.

The power supply management services segment has responsibility for FirstEnergy’s generation operations. Its net income is primarily derived from all electric generation sales revenues, which consist of generation services to regulated franchise customers who have not chosen an alternative generation supplier, retail sales in deregulated markets and all domestic unregulated electricity sales in the retail and wholesale markets, less the related costs of electricity generation and sourcing of commodity requirements. Its net income also reflects the expense of the intersegment generating unit leases discussed above and property taxes related to those generating units.

Segment reporting for interim periods in 2004 was reclassified to conform with the current year business segment organization and operations that were reported in the 2004 Form 10-K, emphasizing FirstEnergy's regulated electric businesses and power supply management operations and the reclassification of discontinued operations (see Note 6). FSG is being disclosed as a reporting segment due to the subsidiaries qualifying as held for sale (see Note 6 for discussion of the divestiture of three of its subsidiaries in 2005). Interest expense on holding company debt and corporate support services revenues and expenses are included in "Reconciling Items."

Segment Financial Information

			Power
			Supply
	Regulated		Management			Facilities						Reconciling
	Services		Services			Services			Other			Adjustments			Consolidated
	*(In millions)*
Three Months Ended:

June 30, 2005
External revenues	$	1,351	$	1,379		$	56		$	137		$	6		$	2,929
Internal revenues		80		-			-			-			(80	)		-
Total revenues		1,431		1,379			56			137			(74	)		2,929
Depreciation and amortization		322		7			-			-			6			335
Net interest charges		99		8			1			2			51			161
Income taxes		186		7			3			4			41			241
Income before discontinued operations		267		11			(3	)		6			(102	)		179
Discontinued operations		-		-			-			(1	)		-			(1	)
Net income		267		11			(3	)		5			(102	)		178
Total assets		28,454		1,601			78			512			566			31,211
Total goodwill		5,946		24			-			63			-			6,033
Property additions		158		66			-			2			7			233

June 30, 2004
External revenues	$	1,278	$	1,550		$	50		$	119		$	(5	)	$	2,992
Internal revenues		80		-			-			-			(80	)		-
Total revenues		1,358		1,550			50			119			(85	)		2,992
Depreciation and amortization		330		9			-			-			10			349
Net interest charges		113		10			-			1			56			180
Income taxes		171		26			-			(22	)		2			177
Income before discontinued operations		234		37			-			36			(105	)		202
Discontinued operations		-		-			1			1			-			2
Net income		234		37			1			37			(105	)		204
Total assets		29,101		1,475			174			604			656			32,010
Total goodwill		5,965		24			37			75			-			6,101
Property additions		129		58			1			1			7			196


Six Months Ended:

June 30, 2005
External revenues	$	2,690	$	2,673		$	102		$	247		$	18		$	5,730
Internal revenues		158		-			-			-			(158	)		-
Total revenues		2,848		2,673			102			247			(140	)		5,730
Depreciation and amortization		698		17			-			1			13			729
Net interest charges		197		18			1			3			113			332
Income taxes		341		(17	)		2			11			26			363
Income before discontinued operations		490		(25	)		(5	)		11			(151	)		320
Discontinued operations		-		-			13			5			-			18
Net income		490		(25	)		8			16			(151	)		338
Total assets		28,454		1,601			78			512			566			31,211
Total goodwill		5,946		24			-			63			-			6,033
Property additions		299		147			1			4			11			462

June 30, 2004
External revenues	$	2,568	$	3,072		$	95		$	234		$	6		$	5,975
Internal revenues		159		-			-			-			(159	)		-
Total revenues		2,727		3,072			95			234			(153	)		5,975
Depreciation and amortization		722		17			1			-			20			760
Net interest charges		219		21			-			2			109			351
Income taxes		316		25			(1	)		(18	)		(30	)		292
Income before discontinued operations		446		36			(2	)		41			(147	)		374
Discontinued operations		-		-			2			2			-			4
Net income		446		36			-			43			(147	)		378
Total assets		29,101		1,475			174			604			656			32,010
Total goodwill		5,965		24			37			75			-			6,101
Property additions		220		102			2			-			11			335

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, fuel marketing revenues, which are reflected as reductions
to expenses for internal management reporting purposes, the impact from the phase-out of the State of Ohio income tax and elimination of intersegment transactions.

17 - FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS

On May 13, 2005, Penn, and on May 18, 2005, OE, CEI and TE, entered into certain agreements described below (Agreements) implementing a series of intra-system generation asset transfers. When concluded, the asset transfers will result in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear, fossil and hydroelectric plants being owned by NGC, and FGCO, respectively. The generating plant interests that are being transferred do not include leasehold interests of CEI, TE and OE in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.

These transactions are being undertaken in connection with the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. FENOC, a subsidiary of FirstEnergy, currently operates and maintains the nuclear generation assets to be transferred. FGCO, as lessee under a master facility lease, leases the non-nuclear generation assets to be transferred and operates and maintains those assets. The transactions will essentially complete the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO, respectively, without impacting the operation of the plants.

As contemplated by the Agreements, the Ohio Companies and Penn intend to transfer their respective interests in the nuclear generation assets to NGC through, in the case of OE and Penn, a spin-off by way of dividend and, in the case of CEI and TE, a sale at net book value. FGCO intends to exercise a purchase option under the Master Lease to acquire the non-nuclear generation assets to be transferred by the Ohio Companies and Penn at the values approved in the Ohio Transition Case.

Consummation of the transactions contemplated by each of the Agreements is subject to receipt of all necessary regulatory authorizations and other consents and approvals. FirstEnergy currently expects to complete the various asset transfers in the second half of 2005.

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	*(In thousands, except per share amounts)*
REVENUES:
Electric utilities	$	2,329,795		$	2,170,570		$	4,638,311		$	4,347,603
Unregulated businesses (Note 2)		599,483			821,592			1,091,686			1,627,462
Total revenues		2,929,278			2,992,162			5,729,997			5,975,065

EXPENSES:
Fuel and purchased power (Note 2)		932,596			1,095,135			1,827,928			2,229,461
Other operating expenses		912,592			832,398			1,805,587			1,631,742
Provision for depreciation		149,025			146,155			291,657			291,965
Amortization of regulatory assets		306,572			270,986			617,413			581,188
Deferral of new regulatory assets		(120,162	)		(68,315	)		(179,669	)		(112,720	)
General taxes		167,865			157,732			353,044			336,722
Total expenses		2,348,488			2,434,091			4,715,960			4,958,358

INCOME BEFORE INTEREST AND INCOME TAXES		580,790			558,071			1,014,037			1,016,707

NET INTEREST CHARGES:
Interest expense		161,714			179,542			326,358			352,048
Capitalized interest		(4,697	)		(5,280	)		(4,952	)		(11,750	)
Subsidiaries’ preferred stock dividends		3,733			5,389			10,286			10,670
Net interest charges		160,750			179,651			331,692			350,968

INCOME TAXES		241,275			176,560			362,550			291,530

INCOME BEFORE DISCONTINUED OPERATIONS		178,765			201,860			319,795			374,209

Discontinued operations (net of income taxes (benefit) of
$(1,282,000) and $993,000 in the three months ended
June 30, and $(9,051,000) and $2,137,000 in the six
months ended June 30, of 2005 and 2004, respectively)
(Note 6)		(773	)		2,185			17,923			3,835

NET INCOME	$	177,992		$	204,045		$	337,718		$	378,044

BASIC EARNINGS PER SHARE OF COMMON STOCK:
Earnings before discontinued operations	$	0.54		$	0.61		$	0.98		$	1.15
Discontinued operations (Note 6)		-			0.01			0.05			0.01
Net earnings per basic share	$	0.54		$	0.62		$	1.03		$	1.16

WEIGHTED AVERAGE NUMBER OF BASIC SHARES
OUTSTANDING		328,063			327,284			327,986			327,171

DILUTED EARNINGS PER SHARE OF COMMON STOCK:
Earnings before discontinued operations	$	0.54		$	0.61		$	0.97		$	1.14
Discontinued operations (Note 6)		-			0.01			0.05			0.01
Net earnings per diluted share	$	0.54		$	0.62		$	1.02		$	1.15

WEIGHTED AVERAGE NUMBER OF DILUTED SHARES
OUTSTANDING		329,879			329,103			329,679			329,061

DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	0.4125		$	0.375		$	0.825		$	0.75

The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	*(In thousands)*

NET INCOME	$	177,992		$	204,045		$	337,718		$	378,044

OTHER COMPREHENSIVE (LOSS) INCOME:
Unrealized gain (loss) on derivative hedges		(6,023	)		19,244			1,300			20,609
Unrealized loss on available for sale securities		(16,137	)		(19,122	)		(24,123	)		(2,193	)
Other comprehensive (loss) income		(22,160	)		122			(22,823	)		18,416
Income tax expense (benefit) related to other
comprehensive income		5,778			(314	)		5,907			(9,785	)
Other comprehensive (loss) income, net of tax		(16,382	)		(192	)		(16,916	)		8,631

COMPREHENSIVE INCOME	$	161,610		$	203,853		$	320,802		$	386,675


The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these
statements.

FIRSTENERGY CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,			December 31,
	2005			2004
	*(In thousands)*
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	49,748		$	52,941
Receivables -
Customers (less accumulated provisions of $35,174,000 and
$34,476,000, respectively, for uncollectible accounts)		1,281,688			979,242
Other (less accumulated provisions of $27,276,000 and
$26,070,000, respectively, for uncollectible accounts)		162,864			377,195
Materials and supplies, at average cost -
Owned		393,999			363,547
Under consignment		114,179			94,226
Prepayments and other		301,557			145,196
		2,304,035			2,012,347
PROPERTY, PLANT AND EQUIPMENT:
In service		22,654,302			22,213,218
Less - Accumulated provision for depreciation		9,576,245			9,413,730
		13,078,057			12,799,488
Construction work in progress		574,178			678,868
		13,652,235			13,478,356
INVESTMENTS:
Nuclear plant decommissioning trusts		1,635,315			1,582,588
Investments in lease obligation bonds		905,754			951,352
Other		772,999			740,026
		3,314,068			3,273,966
DEFERRED CHARGES:
Regulatory assets		5,178,218			5,532,087
Goodwill		6,032,539			6,050,277
Other		730,148			720,911
		11,940,905			12,303,275
	$	31,211,243		$	31,067,944
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	943,740		$	940,944
Short-term borrowings		554,824			170,489
Accounts payable		696,310			610,589
Accrued taxes		684,259			657,219
Other		874,839			929,194
		3,753,972			3,308,435
CAPITALIZATION:
Common stockholders’ equity -
Common stock, $0.10 par value, authorized 375,000,000 shares -
329,836,276 shares outstanding		32,984			32,984
Other paid-in capital		7,047,469			7,055,676
Accumulated other comprehensive loss		(330,028	)		(313,112	)
Retained earnings		1,924,097			1,856,863
Unallocated employee stock ownership plan common stock -
1,830,883 and 2,032,800 shares, respectively		(34,126	)		(43,117	)
Total common stockholders' equity		8,640,396			8,589,294
Preferred stock of consolidated subsidiaries		213,719			335,123
Long-term debt and other long-term obligations		9,568,954			10,013,349
		18,423,069			18,937,766
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		2,411,166			2,324,097
Asset retirement obligations		1,112,940			1,077,557
Power purchase contract loss liability		1,856,482			2,001,006
Retirement benefits		1,287,345			1,238,973
Lease market valuation liability		893,800			936,200
Other		1,472,469			1,243,910
		9,034,202			8,821,743
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 13)
	$	31,211,243		$	31,067,944

The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these
balance sheets.

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	*(In thousands)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	177,992		$	204,045		$	337,718		$	378,044
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation		149,025			146,155			291,657			291,965
Amortization of regulatory assets		306,572			270,986			617,413			581,188
Deferral of new regulatory assets		(120,162	)		(68,315	)		(179,669	)		(112,720	)
Nuclear fuel and lease amortization		18,930			23,132			37,578			45,006
Amortization of electric service obligation		(10,054	)		(4,818	)		(15,505	)		(9,541	)
Deferred purchased power and other costs		(82,990	)		(60,974	)		(192,223	)		(144,881	)
Deferred income taxes and investment tax credits, net		76,041			(100,056	)		61,885			(94,133	)
Deferred rents and lease market valuation liability		(65,446	)		(64,287	)		(101,109	)		(80,584	)
Accrued retirement benefit obligations		32,269			39,864			48,372			64,500
Accrued compensation, net		4,447			17,935			(37,275	)		22,322
Commodity derivative transactions, net		13,921			(23,992	)		14,108			(54,779	)
Loss (income) from discontinued operations (Note 6)		773			(2,185	)		(17,923	)		(3,835	)
Decrease (increase) in operating assets -
Receivables		(225,972	)		(101,304	)		(135,309	)		171,442
Materials and supplies		(59,309	)		(20,617	)		(51,852	)		963
Prepayments and other current assets		(53,095	)		(42,563	)		(159,217	)		(89,594	)
Increase (decrease) in operating liabilities -
Accounts payable		42,612			68,376			104,031			(108,642	)
Accrued taxes		(1,557	)		113,874			39,155			144,659
Accrued interest		(112,388	)		(93,341	)		(3,787	)		(7,063	)
Prepayment for electric service - education programs		241,685			-			241,685			-
Other		29,032			29,645			31,383			(14,906	)
Net cash provided from operating activities		362,326			331,560			931,116			979,411

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing -
Long-term debt		245,350			303,162			245,350			884,720
Short-term borrowings, net		245,803			-			385,614			-
Redemptions and Repayments -
Preferred stock		(41,750	)		-			(139,650	)		-
Long-term debt		(452,860	)		(721,023	)		(688,748	)		(989,943	)
Short-term borrowings, net		-			(59,563	)		-			(447,104	)
Net controlled disbursement activity		29,461			25,385			(476	)		(17,271	)
Common stock dividend payments		(135,178	)		(121,321	)		(270,484	)		(243,786	)
Net cash used for financing activities		(109,174	)		(573,360	)		(468,394	)		(813,384	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(232,791	)		(196,094	)		(461,675	)		(334,500	)
Proceeds from asset sales		7,483			200,008			61,207			211,447
Nonutility generation trust contributions		-			-			-			(50,614	)
Contributions to nuclear decommissioning trusts		(25,372	)		(25,372	)		(50,742	)		(50,742	)
Cash investments		8,217			6,738			35,121			26,956
Other		(42,132	)		75,789			(49,826	)		16,989
Net cash provided from (used for) investing activities		(284,595	)		61,069			(465,915	)		(180,464	)

Net decrease in cash and cash equivalents		(31,443	)		(180,731	)		(3,193	)		(14,437	)
Cash and cash equivalents at beginning of period		81,191			280,269			52,941			113,975
Cash and cash equivalents at end of period	$	49,748		$	99,538		$	49,748		$	99,538

The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these
statements.

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, 2005, and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2005 and 2004. 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, 2004, and the related consolidated statements of income, capitalization, common stockholders’ equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(K) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 7 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

July 29, 2005

FIRSTENERGY CORP.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

EXECUTIVE SUMMARY

Net income in the second quarter of 2005 was $178 million, or basic and diluted earnings of $0.54 per share of common stock compared to net income of $204 million, or basic and diluted earnings of $0.62 per share of common stock for the second quarter of 2004. Net income in the first six months of 2005 was $338 million, or basic earnings of $1.03 per share of common stock ($1.02 diluted) compared to $378 million in the first six months of 2004, or basic earnings of $1.16 per share of common stock ($1.15 diluted).

During the second quarter of 2005, JCP&L settled two rate cases, resulting in a one-time net gain of $0.05 per share of common stock for the quarter. Also, due to a tax law change in the State of Ohio, FirstEnergy wrote-off $72 million of net deferred tax benefits that are not expected to be realized during a five-year phase-out period for Ohio income taxes. This write-off reduced second-quarter earnings per share by $0.22.

During the second quarter of 2005, both the Beaver Valley Unit 2 and Perry stations conducted nuclear refueling outages. Perry’s outage (including an unplanned extension) began on February 22, 2005 and continued into the second quarter, ending on May 6, 2005. The Beaver Valley outage began on April 4, 2005 and ended on April 28, 2005.

On April 21, 2005, FENOC announced that it received a notice of violation by the NRC and a proposed $5.45 million fine related to the reactor head degradation at the Davis-Besse Nuclear Power Station. The corrosion on the plant’s reactor head was discovered during a comprehensive inspection and was reported to the NRC in March 2002. Subsequently, FENOC investigated the causes of the problem, replaced the reactor head, and made numerous staff changes, as well as enhancements to plant programs and equipment. Davis-Besse has operated safely and reliably after successfully restarting in March 2004. The NRC said in a letter to FENOC that this action does not reflect the current performance of Davis-Besse and no further civil enforcement action is expected, absent any new information from the Department of Justice. On May 20, 2005, FENOC announced that it had been notified by the NRC that the Davis-Besse Nuclear Power Station would return to the standard NRC reactor oversight process, effective July 1, 2005. The NRC’s inspections of Davis-Besse are augmented to reflect commitments in a confirmatory order associated with the startup of the facility, and a previous NRC White Finding related to the performance of the emergency sirens.

FirstEnergy announced on May 18, 2005 that it had received approval from the PUCO to defer for future recovery charges from MISO incurred by FirstEnergy’s Ohio Companies. The deferred charges for 2005 are related to MISO’s administrative operation of FirstEnergy’s transmission systems and the daily and hourly spot energy market. A request filed with the PUCO to recover these charges over a five-year period, beginning in 2006, is pending.

FirstEnergy’s JCP&L subsidiary announced on May 25, 2005, that the NJBPU approved a stipulated agreement with the NJPBU staff and the Division of Ratepayer Advocate resolving JCP&L’s Phase II rate case filing which resulted in the one-time gain discussed above, and a second stipulated settlement agreement with the NJBPU staff resolving the motion for reconsideration of the 2003 decision in its Phase I rate proceeding.

Together, the two stipulated settlements resulted in a net average increase, effective June 1, 2005, of approximately $1.14 per month in the delivery portion of the bill for residential customers using 500 KWH of electricity. The increase, averaging 2.4% per customer, is JCP&L’s first since 1993, and follows an 11% decrease implemented between 1999 and 2003 under New Jersey’s Electric Discount and Energy Competition Act. The stipulated settlements, which are expected to increase JCP&L’s annual revenues by approximately $51 million, include a commitment by JCP&L to maintain a target level of customer service reliability.

On May 27, 2005, FirstEnergy’s Ohio Companies filed with the PUCO a request to establish a generation charge adjustment factor, as permitted under the Ohio Companies’ previously approved Rate Stabilization Plan. If approved, the rider would average $0.002554 per KWH, effective January 1, 2006, for all classes of customers. The filing reflects projected increases in fuel and related costs in 2006 compared with 2002 costs.

FIRSTENERGY’S BUSINESS

FirstEnergy is a registered public utility holding company headquartered in Akron, Ohio that operates primarily through two core business segments.

Regulated Services transmits, distributes and sells electric power through eight electric utility operating companies that collectively comprise the nation’s fifth largest investor-owned electric system, serving 4.4 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey. This business segment primarily derives its revenue from the delivery of electricity, including transition cost recovery.

Power Supply Management Services supplies the power needs of end-use customers (principally in Ohio, Pennsylvania and New Jersey) through retail and wholesale arrangements, including sales to meet the PLR requirements of FirstEnergy’s Ohio Companies and Penn. This business segment operates the generating facilities of the Ohio Companies and Penn and purchases from the wholesale market to meet its sales obligations. It leases fossil facilities from the EUOC and purchases the entire output of the EUOC nuclear plants. This business segment principally derives its revenues from electric generation sales.

Other operating segments provide a wide range of services, including heating, ventilation, air-conditioning, refrigeration, electrical and facility control systems, high-efficiency electrotechnologies and telecommunication services. FirstEnergy continues to divest these non-core businesses. See Note 6 to the consolidated financial statements. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as "reportable segments".

FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS

On May 13, 2005, Penn, and on May 18, 2005, OE, CEI and TE, entered into certain agreements described below (Agreements) implementing a series of intra-system generation asset transfers. When concluded, the asset transfers will result in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear, fossil and hydroelectric plants being owned by NGC, and FGCO, respectively. The generating plant interests that are being transferred do not include leasehold interests of CEI, TE and OE in plants that are currently subject to sale and leaseback arrangements with non-affiliates.

As contemplated by the Agreements, the Ohio Companies and Penn intend to transfer their respective interests in the nuclear generation assets to NGC through, in the case of OE and Penn, a spin-off by way of a dividend and, in the case of CEI and TE, a sale at net book value. FGCO intends to exercise a purchase option under the Master Lease to acquire the non-nuclear generation assets to be transferred by the Ohio Companies at the values approved in the Ohio transition case.

RESULTS OF OPERATIONS

The financial results discussed below include revenues and expenses from transactions among our business segments. A reconciliation of segment financial results is provided in Note 16 to the consolidated financial statements. The FSG business segment is included in "Other and Reconciling Adjustments" in this discussion due to its immaterial impact on current period financial results, but is presented separately in segment information provided in Note 16 to the consolidated financial statements. Net income (loss) by major business segment was as follows:

	Three Months Ended									Six Months Ended
	June 30,						Increase			June 30,						Increase
	2005			2004			(Decrease)			2005			2004			(Decrease)
	*(In millions, except per share amounts)*
Net Income (Loss)
By Business Segment:
Regulated Services	$	267		$	234		$	33		$	490		$	446		$	44
Power supply management services		11			37			(26	)		(25	)		36			(61	)
Other and reconciling adjustments*		(100	)		(67	)		(33	)		(127	)		(104	)		(23	)
Total	$	178		$	204		$	(26	)	$	338		$	378		$	(40	)

Basic Earnings Per Share:
Income before discontinued operations		$0.54			$0.61			$ (0.07	)		$0.98			$1.15			$ (0.17	)
Discontinued operations		-			0.01			(0.01	)		0.05			0.01			0.04
Net earnings per basic share		$0.54			$0.62			$ (0.08	)		$1.03			$1.16			$ (0.13	)

Diluted Earnings Per Share:
Income before discontinued operations		$0.54			$0.61			$ (0.07	)		$0.97			$1.14			$ (0.17	)
Discontinued operations		-			0.01			(0.01	)		0.05			0.01			0.04
Net earnings per diluted share		$0.54			$0.62			$ (0.08	)		$1.02			$1.15			$ (0.13	)

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

Earnings in the second quarter of 2005 included a net gain resulting from the JCP&L rate settlement of $16 million (or $0.05 per share) and additional income tax expense of $72 million (or $0.22 per share) from the enactment of new Ohio tax legislation. This compares to the second quarter of 2004 which included a loss from the sale of GLEP of approximately $7 million ($0.02 per share) and a litigation settlement loss of $11 million ($0.03 per share). In addition to the second quarter items, net income in the first six months of 2005 included $22 million ($0.07 per share) of gains from the disposition of non-core assets, an EPA settlement loss of $14 million ($0.04 per share) and an NRC fine of $3 million ($0.01 per share).

A decrease in wholesale electric revenues and purchased power costs in the second quarter and first six months of 2005 from the corresponding periods last year primarily resulted from FES recording PJM sales and purchased power transactions on an hourly net position basis beginning in the first quarter of 2005 compared with recording each discrete transaction (on a gross basis) in the same period of 2004. This change had no impact on earnings and resulted from the dedication of FirstEnergy’s Beaver Valley Power Station to PJM in January 2005. FirstEnergy believes that a net-hourly-position measure of revenues and purchased power transactions is required as these generation assets are now dedicated in PJM where FirstEnergy has third-party customers. Wholesale electric revenues and purchased power costs in the second quarter of 2004 each included $283 million from these transactions recorded on a gross basis — the first six months of 2004 included $564 million from these transactions.

Excluding the effect of recording the wholesale electric revenue transactions in PJM on a gross basis in 2004, operating revenues in the second quarter and first six months of 2005 increased, reflecting in large part warmer than normal temperatures in the second quarter of 2005. Net income in the regulated services segment increased due to the additional demand. However, net income for the power supply management services segment was lower in both the second quarter and first six months of 2005 as a result of higher costs for fossil fuel, purchased power and nuclear refueling costs which, in aggregate, more than offset the revenue from increased electric generation sales. The impact of the new Ohio tax legislation is included with FirstEnergy’s other operating segments and reconciling adjustments.

Summary of Results of Operations - Second Quarter of 2005 Compared with the Second Quarter of 2004

Financial results for FirstEnergy and its major business segments in the second quarter of 2005 and 2004 were as follows:

				Power
				Supply		Other and
2nd Quarter 2005	Regulated			Management		Reconciling			FirstEnergy
Quarterly Financial Results	Services			Services		Adjustments			Consolidated
	*(In millions)*
Revenue:
External
Electric	$	1,165		$	1,314	$	-		$	2,479
Other		186			65		199			450
Internal		80			-		(80	)		-
Total Revenues		1,431			1,379		119			2,929

Expenses:
Fuel and purchased power		-			933		-			933
Other operating		408			399		106			913
Provision for depreciation		135			7		6			148
Amortization of regulatory assets		307			-		-			307
Deferral of new regulatory assets		(120	)		-		-			(120	)
General taxes		149			14		4			167
Total Expenses		879			1,353		116			2,348

Net interest charges		99			8		54			161
Income taxes		186			7		48			241
Income before discontinued operations		267			11		(99	)		179
Discontinued operations		-			-		(1	)		(1	)
Net Income (Loss)	$	267		$	11	$	(100	)	$	178

					Power
					Supply		Other and
2nd Quarter 2004	Regulated				Management		Reconciling			FirstEnergy
Quarterly Financial Results	Services				Services		Adjustments			Consolidated
	*(In millions)*
Revenue:
External
Electric	$	1,125		$		1,520	$	-			$	2,645
Other		153				30		164				347
Internal		80				-		(80	)			-
Total Revenues		1,358				1,550		84				2,992

Expenses:
Fuel and purchased power		-				1,095		-				1,095
Other operating		375				355		101				831
Provision for depreciation		127				9		10				146
Amortization of regulatory assets		271				-		-				271
Deferral of new regulatory assets		(68	)			-		-				(68	)
General taxes		135				18		5				158
Total Expenses		840				1,477		116				2,433

Net interest charges		113				10		57				180
Income taxes		171				26		(20	)			177
Income before discontinued operations		234				37		(69	)			202
Discontinued operations		-				-		2				2
Net Income (Loss)	$	234		$		37	$	(67	)		$	204

Change Between				Power
2nd Quarter 2005 and 2004				Supply			Other and
Quarterly Financial Results	Regulated			Management			Reconciling			FirstEnergy
Increase (Decrease)	Services			Services			Adjustments			Consolidated
	*(In millions)*
Revenue:
External
Electric	$	40		$	(206	)	$	-			$	(166	)
Other		33			35			35				103
Internal		-			-			-				-
Total Revenues		73			(171	)		35				(63	)

Expenses:
Fuel and purchased power		-			(162	)		-				(162	)
Other operating		33			44			5				82
Provision for depreciation		8			(2	)		(4	)			2
Amortization of regulatory assets		36			-			-				36
Deferral of new regulatory assets		(52	)		-			-				(52	)
General taxes		14			(4	)		(1	)			9
Total Expenses		39			(124	)		-				(85	)

Net interest charges		(14	)		(2	)		(3	)			(19	)
Income taxes		15			(19	)		68				64
Income before discontinued operations		33			(26	)		(30	)			(23	)
Discontinued operations		-			-			(3	)			(3	)
Net Income (Loss)	$	33		$	(26	)	$	(33	)		$	(26	)

Regulated Services - Second Quarter 2005 Compared with Second Quarter 2004

Net income increased to $267 million from $234 million (or 14%) in the second quarter of 2005 with increased operating revenues partially offset by higher operating expenses and taxes.

Revenues -

The increase in total revenues resulted from the following sources:

	Three Months Ended
	June 30,				Increase
Revenues by Type of Service	2005		2004		(Decrease)
	*(In millions)*

Distribution services	$	1,165	$	1,125	$	40
Transmission services		105		65		40
Lease revenue from affiliates		80		80		-
Other		81		88		(7	)
Total Revenues	$	1,431	$	1,358	$	73

Changes in distribution deliveries by customer class in the second quarter of 2005 are summarized in the following table:

	Increase
Electric Distribution Deliveries	(Decrease)
Residential		9.5	%
Commercial		2.9	%
Industrial		(3.8	)%
Total Distribution Deliveries		2.4	%

Increased consumption offset in part by lower prices resulted in higher distribution delivery revenue. The following table summarizes major factors contributing to the $40 million increase in distribution services revenue in the second quarter of 2005:

	Increase
Sources of Change in Distribution Revenues	(Decrease)
	*(In millions)*

Changes in customer usage	$	52
Changes in prices:
Rate changes --
Ohio shopping incentive		(11	)
Other		(1	)
Net Increase in Distribution Revenues	$	40

Distribution revenues benefited from warmer than normal temperatures in the second quarter of 2005 that increased the air-conditioning load of residential and commercial customers. Reduced industrial demand as a result of a softening in the automotive and steel-related sectors offset part of the weather-induced increase in load. A reduction in prices primarily resulted from additional credits provided to customers under the Ohio transition plan - those changes do not affect current period earnings due to deferral of the incentives for future recovery from customers.

Transmission revenues increased $40 million in the second quarter of 2005 from the same period last year due in part to an amended power supply agreement with FES in June 2004. Other revenues decreased $7 million due in part to a reduction in JCP&L transition bond revenues.

Expenses-

The higher revenues discussed above were partially offset by the following increases in expenses:

· Higher transmission expenses of $42 million due in part to an amended power supply agreement with FES, which also increased revenue;

· Increased provision for depreciation of $8 million due to property additions;

· Additional amortization of regulatory assets of $36 million, principally due to increased amortization of Ohio transition costs;

Increased general taxes of $14 million due to additional Pennsylvania gross receipts tax and the absence in 2005 of Pennsylvania property tax refunds recognized in the second quarter of 2004; and

· Higher income taxes of $15 million due to increased taxable income.

Partially offsetting these higher costs were two factors:

· Additional deferral of regulatory assets of $52 million, primarily the PUCO-approved MISO administrative costs, JCP&L reliability improvements and related interest (see Note 14 - Regulatory Matters - Transmission; New Jersey); and

· Lower interest charges of $14 million resulting from debt and preferred stock redemptions and refinancings.

Power Supply Management Services - Second Quarter 2005 Compared with Second Quarter 2004

Net income for this segment decreased to $11 million in the second quarter of 2005 from $37 million in the same period last year. A decrease in the gross generation margin and higher non-fuel nuclear costs resulted in lower net income.

Generation Margin -

The gross generation margin in the second quarter of 2005 decreased by $44 million compared to the same period of 2004, as shown in the table below.

	Three Months Ended
	June 30,
Gross Generation Margin	2005		2004		(Decrease)
	*(In millions)*
Electric generation revenue	$	1,314	$	1,520	$	(206	)
Fuel and purchased power costs		933		1,095		(162	)
Gross generation margin	$	381	$	425	$	(44	)

Excluding the effect of recording PJM sales and purchases of $283 million on a gross basis in 2004, electric generation revenues increased $77 million while fuel and purchased power costs increased $121 million in the second quarter of 2005. The higher fuel and purchased power costs primarily resulted from higher prices which more than offset the benefit of increased sales to the retail and wholesale markets.

Revenues -

Excluding the effect of the change in recording PJM wholesale transactions, electric generation revenues increased $77 million in the second quarter of 2005 compared to the same period of 2004 primarily as a result of a 1.5% increase in KWH sales and higher unit prices. The additional retail sales reduced energy available for sale to the wholesale market resulting in a 0.9% reduction in those sales (before the PJM adjustment). Overall, revenues to the wholesale market increased due to a 7% rise in prices.

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

	Three Months Ended
	June 30,				Increase
Revenues by Type of Service	2005		2004		(Decrease)
	*(In millions)*
Electric generation sales:
Retail	$	989	$	930	$	59
Wholesale		325		307		18
Total electric generation sales		1,314		1,237		77
Transmission		15		23		(8	)
Other		50		7		43
Total		1,379		1,267		112
PJM gross transactions		-		283		(283	)
Total Revenues	$	1,379	$	1,550	$	(171	)

Changes in KWH sales are summarized in the following table:

Electric Generation	Increase
	(Decrease)

Retail		2.3	%
Wholesale		(0.9	)%
Total Electric Generation		1.5	%*

* Decrease of 15.6% including the effect of the PJM revision.

The other revenues increase in the second quarter of 2005 includes $40 million related to gas commodity operations. These transactions resulted from procuring fuel for gas-fired peaking capacity that was ultimately not required for generation and subsequently sold into the wholesale market. Related gas procurement costs of $38 million are reflected in the other operating costs in the second quarter of 2005.

Expenses -

Excluding the effect of the $283 million of PJM purchased power costs recorded on a gross basis in 2004, total operating expenses, net interest charges and income taxes increased in aggregate by $138 million in the second quarter of 2005 compared to the same period of 2004. Higher fuel and purchased power costs contributed $121 million ($162 million, net of $283 million PJM effect) of the increase, resulting from higher fuel costs of $89 million and increased purchased power costs of $32 million. Factors contributing to the higher costs are summarized in the following table:

	Increase
Source of Change in Fuel and Purchased Power	(Decrease)
	*(In millions)*
Fuel:
Change due to price	$	65
Change due to volume		24
		89
Purchased Power:
Change due to price		64
Change due to volume		(9	)
Deferred costs		(23	)
		32

Net Increase in Fuel and Purchased Power Costs	$	121

FirstEnergy’s fleet of generating plants established a new output record of 19.1 billion KWH. Increased coal and emission allowance costs combined to increase fossil fuel expense. Higher coal costs resulted from increased purchases, market adjustment provisions in coal contracts reflecting higher market prices and increased transportation costs. Emission allowance costs increased primarily from higher prices. To a lesser extent, fuel expense increased due to the increased mix of fossil versus nuclear generation resulting in large part from the nuclear refueling outages in the second quarter of 2005 following a year with no scheduled nuclear outages. Fossil generation increased 12% in the second quarter of 2005 while nuclear generation decreased by 16%.

Non-fuel nuclear costs increased $33 million primarily due to costs from the Beaver Valley Unit 2 refueling outage (started April 4, 2005) and to a lesser extent from the Perry Unit 1 outage initiated in the first quarter of 2005 and completed May 6, 2005. There were no nuclear refueling outages in the second quarter of 2004.

Partially offsetting these higher costs were the following factors:

· Reduced non-fuel fossil generation expense of $7 million due to different maintenance outage schedules;

· Lower transmission costs of $10 million due in part to the amended power supply agreement that resulted in the regulated services segment assuming certain transmission obligations previously borne by the power supply management services segment; and

· Lower income taxes of $19 million due to lower taxable income.

Other - Second Quarter 2005 Compared with Second Quarter 2004

FirstEnergy’s financial results from other operating segments and reconciling adjustments, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a net decrease in FirstEnergy’s net income in the second quarter of 2005 compared to the same quarter of 2004. The decrease was primarily due to the effect of the new Ohio tax legislation, partially offset by the absence in the second quarter of 2005 of a litigation settlement loss of $11 million and the after-tax loss on the sale of GLEP of $7 million recorded in the second quarter of 2004.

Summary of Results of Operations - First Six Months of 2005 Compared with the First Six Months of 2004

Financial results for FirstEnergy and its major business segments for the first six months of 2005 and 2004 were as follows:

				Power
				Supply			Other and
First Six Months of 2005	Regulated			Management			Reconciling			FirstEnergy
Financial Results	Services			Services			Adjustments			Consolidated
	*(In millions)*
Revenue:
External
Electric	$	2,327		$	2,589		$	-		$	4,916
Other		363			84			367			814
Internal		158			-			(158	)		-
Total Revenues		2,848			2,673			209			5,730

Expenses:
Fuel and purchased power		-			1,828			-			1,828
Other operating		826			807			172			1,805
Provision for depreciation		261			17			14			292
Amortization of regulatory assets		617			-			-			617
Deferral of new regulatory assets		(180	)		-			-			(180	)
General taxes		296			45			12			353
Total Expenses		1,820			2,697			198			4,715

Net interest charges		197			18			117			332
Income taxes		341			(17	)		39			363
Income before discontinued operations		490			(25	)		(145	)		320
Discontinued operations		-			-			18			18
Net Income (Loss)	$	490		$	(25	)	$	(127	)	$	338

				Power
				Supply		Other and
First Six Months of 2004	Regulated			Management		Reconciling			FirstEnergy
Financial Results	Services			Services		Adjustments			Consolidated
	*(In millions)*
Revenue:
External
Electric	$	2,279		$	3,022	$	-		$	5,301
Other		289			50		335			674
Internal		159			-		(159	)		-
Total Revenues		2,727			3,072		176			5,975

Expenses:
Fuel and purchased power		-			2,229		-			2,229
Other operating		741			702		189			1,632
Provision for depreciation		254			17		21			292
Amortization of regulatory assets		581			-		-			581
Deferral of new regulatory assets		(113	)		-		-			(113	)
General taxes		283			42		12			337
Total Expenses		1,746			2,990		222			4,958

Net interest charges		219			21		111			351
Income taxes		316			25		(49	)		292
Income before discontinued operations		446			36		(108	)		374
Discontinued operations		-			-		4			4
Net Income (Loss)	$	446		$	36	$	(104	)	$	378

				Power
Change Between				Supply			Other and
First Six Months 2005 vs. 2004	Regulated			Management			Reconciling			FirstEnergy
Financial Results	Services			Services			Adjustments			Consolidated
Increase (Decrease)	*(In millions)*
Revenue:
External
Electric	$	48		$	(433	)	$	-		$	(385	)
Other		74			34			32			140
Internal		(1	)		-			1			-
Total Revenues		121			(399	)		33			(245	)

Expenses:
Fuel and purchased power		-			(401	)		-			(401	)
Other operating		85			105			(17	)		173
Provision for depreciation		7			-			(7	)		-
Amortization of regulatory assets		36			-			-			36
Deferral of new regulatory assets		(67	)		-			-			(67	)
General taxes		13			3			-			16
Total Expenses		74			(293	)		(24	)		(243	)

Net interest charges		(22	)		(3	)		6			(19	)
Income taxes		25			(42	)		88			71
Income before discontinued operations		44			(61	)		(37	)		(54	)
Discontinued operations		-			-			14			14
Net Income (Loss)	$	44		$	(61	)	$	(23	)	$	(40	)

Regulated Services - First Six Months of 2005 Compared with First Six Months of 2004

Net income increased to $490 million in the first six months of 2005 from $446 million in the same period of 2004 due to increased operating revenues partially offset by higher operating expenses and taxes.

Revenues -

The increase in total revenues resulted from the following sources:

	Six Months Ended
	June 30,				Increase
Revenues by Type of Service	2005		2004		(Decrease)
	*(In millions)*

Distribution services	$	2,327	$	2,279	$	48
Transmission services		197		130		67
Lease revenue from affiliates		158		159		(1	)
Other		166		159		7
Total Revenues	$	2,848	$	2,727	$	121

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

Electric Distribution Deliveries	Increase

Residential		3.8	%
Commercial		3.8	%
Industrial		0.1	%
Total Distribution Deliveries		2.5	%

Increased consumption offset in part by lower prices resulted in higher distribution delivery revenue. The following table summarizes major factors contributing to the $48 million increase in distribution services revenue in the first half of 2005:

	Increase
Sources of Change in Distribution Revenues	(Decrease)
	*(In millions)*

Changes in customer usage	$	75
Changes in prices:
Rate changes -
Ohio shopping incentive		(22	)
Other		8
Rate mix and other		(13	)
Net Increase in Distribution Revenues	$	48

Distribution revenues benefited from warmer than normal temperatures in the second quarter of 2005 that increased the air-conditioning load of residential and commercial customers. Sales to industrial customers were flat due in part to a softening in automotive and steel-related markets. A reduction in prices primarily resulted from additional shopping credits under the Ohio transition plan.

Transmission revenues increased $67 million in the first six months of 2005 from the same period last year due in part to the amended power supply agreement with FES in June 2004. Other revenues increased $7 million primarily due to a payment received under a contract provision associated with the prior sale of TMI, which was offset in part by reduced JCP&L transition bond revenue.

Expenses-

The higher revenues discussed above were partially offset by the following increases in expenses:

· Higher transmission expenses of $85 million due in part to the amended power supply agreement with FES, which also increased revenue;

· Increased provision for depreciation of $7 million reflecting the effect of property additions and additional costs for decommissioning the Saxton nuclear unit;

· Additional amortization of regulatory assets of $36 million, principally due to amortization of Ohio transition costs;

·	Increased general taxes of $13 million related to additional Pennsylvania gross receipts tax and the absence in 2005 of Pennsylvania property tax refunds recognized in the second quarter of 2004; and

· Higher income taxes of $25 million due to increased taxable income.

Partially offsetting these higher costs were two factors:

· Additional deferral of regulatory assets of $67 million, primarily the PUCO-approved MISO administrative costs, JCP&L reliability improvements, shopping incentive credits and related interest on those deferrals (see Note 14 - Regulatory Matters - Transmission, New Jersey); and

· Lower interest charges of $22 million resulting from debt and preferred stock redemptions.

Power Supply Management Services - First Six Months of 2005 Compared with the First Six Months of 2004

The net loss for this segment was $25 million in the first six months of 2005 compared to net income of $36 million in the same period last year. A reduction in the gross generation margin, higher nuclear operating costs and amounts recognized for fines, penalties and obligations associated with proceedings involving the Sammis Plant and the Davis-Besse Nuclear Power Station produced the net loss.

Generation Margin -

The gross generation margin in the first six months of 2005 decreased by $32 million compared to the same period of 2004, as shown in the table below.

	Six Months Ended
	June 30,
Gross Generation Margin	2005		2004		(Decrease)
	*(In millions)*

Electric generation revenue	$	2,589	$	3,022	$	(433	)
Fuel and purchased power costs		1,828		2,229		(401	)
Gross Generation Margin	$	761	$	793	$	(32	)

Excluding the effect of PJM sales and purchases of $564 million recorded on a gross basis in 2004, electric generation revenues increased $131 million while fuel and purchased power costs increased $163 million. The higher fuel and purchased power costs primarily resulted from higher prices which more than offset the benefit of increased sales to retail and wholesale markets.

Revenues -

Excluding the effect of the change in recording PJM wholesale transactions, electric generation revenues increased $131 million in the first six months of 2005 compared to the same period of 2004 as a result of a 0.9% increase in KWH sales and higher unit prices. Additional retail sales reduced energy available for sale to the wholesale market.

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

	Six Months Ended
	June 30,				Increase
Revenues by Type of Service	2005		2004		(Decrease)
	*(In millions)*

Electric generation sales:
Retail	$	1,969	$	1,864	$	105
Wholesale		620		594		26
Total Electric Generation Sales		2,589		2,458		131
Transmission		25		37		(12	)
Other		59		13		46
Total		2,673		2,508		165
PJM gross transactions		-		564		(564	)
Total Revenues	$	2,673	$	3,072	$	(399	)

Changes in KWH sales are summarized in the following table:

	Increase
Electric Generation	(Decrease)
Retail		1.7	%
Wholesale		(1.8	)%
Total Electric Generation		0.9	%*

* Decrease of 15.8% including the effect of the PJM revision.

The other revenues increase in the first six months of 2005 primarily resulted from the $40 million of revenues from the gas commodity operations previously discussed in the second quarter 2005 results analysis.

Expenses -

Excluding the effect of the $564 million of PJM purchased power costs recorded on a gross basis in 2004, total operating expenses, net interest charges and income taxes increased in aggregate by $226 million. Higher fuel and purchased power costs contributed $163 million of the increase, resulting from higher fuel costs of $123 million and increased purchased power costs of $40 million. Factors contributing to the higher costs are summarized in the following table:

	Increase
Source of Change in Fuel and Purchased Power	(Decrease)
	*(In millions)*

Fuel:
Change due to price	$	88
Change due to volume		35
		123

Purchased Power:
Change due to price		124
Change due to volume		(36	)
Deferred costs		(48	)
		40

Net Increase in Fuel and Purchased Power Costs	$	163

FirstEnergy’s fleet of generating plants established a new output record of 37.9 billion KWH. Increased coal and emission allowance costs combined to increase fossil fuel expense. Higher coal costs resulted from increased purchases, market adjustment provisions in coal contracts reflecting higher market prices and increased transportation costs. Emission allowance costs increased primarily from higher prices. To a lesser extent, fuel expense increased due to the increased mix of fossil versus nuclear generation resulting in large part from the nuclear refueling outages in first six months of 2005 following a year with no scheduled nuclear outages. Fossil generation increased 10% in the first six months of 2005 while nuclear generation decreased by 14%.

Non-fuel nuclear costs increased $100 million due primarily to refueling outages at Perry Unit 1 (including an unplanned extension) and Beaver Valley Unit 2 and a scheduled 23-day mid-cycle inspection outage at the Davis-Besse nuclear plant. There were no scheduled nuclear outages in the first six months of 2004.

Partially offsetting these higher costs were the following factors:

· Reduced non-fuel fossil generation expense of $17 million due to different maintenance outage schedules;

· Lower transmission costs of $37 million due in part to the amended power supply agreement that resulted in the regulated services segment assuming certain transmission obligations previously borne by the power supply management services segment; and

· Lower income taxes of $42 million due to lower taxable income.

Other - First Six Months of 2005 Compared with the First Six Months of 2004.

FirstEnergy’s financial results from other operating segments and reconciling adjustments, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a net decrease in FirstEnergy’s net income in the first six months of 2005 compared to the same period of 2004. The decrease primarily reflected the effect of the new Ohio tax legislation (discussed in the Other - Second Quarter 2005 results analysis section), partially offset by the effect of discontinued operations, which included an after-tax net gain of $17 million (see Note 6). The following table summarizes the sources of income from discontinued operations:

	Six Months Ended
	June 30,				Increase
	2005		2004		(Decrease)
	*(In millions)*
Discontinued operations (net of tax)
Gain on sale:
Natural gas business	$	5	$	-	$	5
FSG and MYR Subsidiaries		12		-		12
Reclassification of operating income		1		4		(3	)
Total	$	18	$	4	$	14

Postretirement Plans

Pension costs were lower in 2005 due to last year’s $500 million voluntary contribution and an increase in the market value of pension plan assets during 2004. Combined with amendments to FirstEnergy’s health care plan in the first quarter of 2005, postretirement benefits expense decreased by $17 million in the second quarter of 2005 and $37 million in the first six months of 2005 compared to the corresponding periods of 2004. The following table summarizes the net pension and OPEB expense (excluding amounts capitalized) for the second quarter and first six months ended June 30, 2005 and 2004.

	Three Months Ended							Six Months Ended
Postretirement	June 30,							June 30,
Benefits Expense *	2005		2004		(Decrease)			2005		2004		(Decrease)
	*(In millions)*

Pension	$	8	$	22	$	(14	)	$	16	$	42	$	(26	)
OPEB		18		21		(3	)		36		47		(11	)
Total	$	26	$	43	$	(17	)	$	52	$	89	$	(37	)

* Excludes the capitalized portion of postretirement benefits costs (see Note 10 for total costs).

The decrease in pension and OPEB expenses are included in various cost categories and have contributed to other cost reductions discussed above.

CAPITAL RESOURCES AND LIQUIDITY

FirstEnergy’s cash requirements in 2005 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing FirstEnergy’s net debt and preferred stock outstanding. Available borrowing capacity under credit facilities will be used to manage working capital requirements. Thereafter, FirstEnergy expects to use a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

The primary source of ongoing cash for FirstEnergy, as a holding company, is cash dividends from its subsidiaries. The holding company also has access to $2.0 billion of short-term financing under a revolving credit facility, subject to short-term debt limitations under current regulatory approvals of $1.5 billion and to outstanding borrowings by subsidiaries of FirstEnergy who are also parties to such facility. In the second quarter of 2005, FirstEnergy received $279 million of cash dividends from its subsidiaries and paid $135 million in cash dividends to its common shareholders - in the first six months of 2005, it received and paid $416 million and $270 million, respectively. There are no material restrictions on the payment of cash dividends by FirstEnergy’s subsidiaries.

As of June 30, 2005, FirstEnergy had $50 million of cash and cash equivalents ($3 million restricted as an indemnity reserve) compared with $53 million ($3 million restricted as an indemnity reserve) as of December 31, 2004. The major sources for 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 and power supply businesses (see "RESULTS OF OPERATIONS" above). Net cash provided by operating activities was $362 million and $332 million in the second quarters of 2005 and 2004, respectively, and $931 million and $979 million in the first six months of 2005 and 2004, respectively, summarized as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Operating Cash Flows	2005			2004			2005		2004
	*(In millions)*

Cash earnings *	$	501		$	377		$	865	$	882
Working capital and other		(139	)		(45	)		66		97
Total cash flows from operating activities	$	362		$	332		$	931	$	979

* Cash earnings are a non-GAAP measure (see reconciliation below).

Cash earnings, as disclosed in the table above, are not a measure of performance calculated in accordance with GAAP. FirstEnergy believes that cash earnings is a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Reconciliation of Cash Earnings	2005			2004			2005			2004
	*(In millions)*

Net income (GAAP)	$	178		$	204		$	338		$	378
Non-cash charges (credits):
Provision for depreciation		149			146			292			292
Amortization of regulatory assets		307			271			617			581
Deferral of new regulatory assets		(120	)		(68	)		(180	)		(113	)
Nuclear fuel and lease amortization		19			23			38			45
Deferred purchased power and other costs		(83	)		(61	)		(192	)		(145	)
Deferred income taxes and investment tax credits		76			(100	)		62			(94	)
Deferred rents and lease market valuation liability		(65	)		(64	)		(101	)		(81	)
Income (loss) from discontinued operations		1			(2	)		(18	)		(4	)
Other non-cash expenses		39			28			9			23
Cash earnings (non-GAAP)	$	501		$	377		$	865		$	882

In the second quarter of 2005, cash earnings increased $124 million from the same period last year as described under "RESULTS OF OPERATIONS." Cash earnings during the first six months of 2005 decreased by $17 million from the same period of 2004. In the second quarter of 2005, compared with the second quarter 2004, the use of cash for working capital increased by $94 million, principally from changes in receivables, accrued taxes, prepayments and materials and supplies, offset in part by accounts payable and funds received for prepaid electric service under the Ohio Schools Council’s Energy for Education Program. The use of cash for receivables resulted principally from the conversion of the CFC receivable sale to an on-balance sheet transaction, which added $155 million of receivables to the balance sheet as of June 30, 2005. The first six months of 2005 compared to the first six months of 2004, working capital changes provided $31 million less cash, compared to the same period of 2005, due in part to changes in receivables, accrued taxes and prepayments, offset by accounts payable and the funds received under the Energy for Education Program.

Cash Flows From Financing Activities

In the second quarter and first six months of 2005, cash used for financing activities was $109 million and $468 million, respectively, compared to $573 million and $813 million in the second quarter and first six months of 2004 respectively. The following table summarizes security issuances and redemptions.

	Three Months Ended					Six Months Ended
	June 30,					June 30,
Securities Issued or Redeemed	2005		2004			2005		2004
	*(In millions)*

New issues
Pollution control notes	$	245	$	-		$	245	$	185
Secured notes		-		300			-		550
Unsecured notes		-		3			-		150
	$	245	$	303		$	245	$	885

Redemptions
First mortgage bonds	$	177	$	290		$	178	$	382
Pollution control notes		247		-			247		-
Secured notes		29		31			48		73
Long-term revolving credit		-		175			215		310
Unsecured notes		-		225			-		225
Preferred stock		42		-			140		-
	$	495	$	721		$	828	$	990

Short-term borrowings, net increase (decrease)	$	246	$	(60	)	$	386	$	(447	)

FirstEnergy had approximately $555 million of short-term indebtedness as of June 30, 2005 compared to approximately $170 million as of December 31, 2004. Available bank borrowings as of June 30, 2005 included the following:

Borrowing Capability	FirstEnergy			OE*		Penelec			Total
	*(In millions)*

Short-term revolving credit**	$	2,000		$	-	$	-		$	2,000
Utilized		(41	)		-		-			(41	)
Letters of credit		(140	)		-		-			(140	)
Net		1,819			-		-			1,819

Short-term bank facilities		-			14		75			89
Utilized		-			-		(75	)		(75	)
Net		-			14		-			14
Total unused borrowing capability	$	1,819		$	14	$	-		$	1,833

* Short-term revolving credit agreement matured on July 1, 2005 and was not renewed.
**Credit facility is also available to OE, Penelec and certain other FirstEnergy subsidiaries, as discussed below.

As of June 30, 2005, the Ohio Companies and Penn had the aggregate capability to issue approximately $4.1 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE and CEI are 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 and CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $668 million and $570 million, respectively, as of June 30, 2005. Under the provisions of its senior note indenture, JCP&L may issue additional FMB only as collateral for senior notes. As of June 30, 2005, JCP&L had the capability to issue $597 million of additional senior notes upon the basis of FMB collateral. Based upon applicable earnings coverage tests in their respective charters, OE, Penn, TE and JCP&L could issue a total of $4.3 billion of preferred stock (assuming no additional debt was issued) as of June 30, 2005. CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred stock.

As of June 30, 2005, approximately $1 billion remained unused under an existing shelf registration statement, filed by FirstEnergy with the SEC in 2003, to support future securities issues. 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.

FirstEnergy’s working capital and short-term borrowing needs are met principally with a $2 billion five-year revolving credit facility that was entered into on June 14, 2005 by FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as borrowers, with a syndicate of banks. The facility replaced FirstEnergy’s $375 million and $1 billion three-year credit agreements, OE’s $125 million three-year credit agreement and OE’s recently-expired $250 million two-year credit agreement. Borrowings under the facility are available to each borrower separately and will mature on the earlier of 364 days from the date of borrowing and the commitment termination date.

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 Limitations¹
	*(In millions)*

FirstEnergy	$2,000	$1,500
OE	500	500
Penn	50	49
CEI	250	500
TE	250	500
JCP&L	425	414
Met-Ed	250	250²
Penelec	250	250²
FES	-³	n/a
ATSI	-³	26

⁽¹⁾ As of June 30, 2005.

⁽²⁾ Excluding amounts which may be borrowed under the Utility Money Pool.

⁽³⁾

Borrowing sublimits for FES and ATSI may be increased to up to $250 million and $100 million, respectively, 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 of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet short-term working capital requirements for FirstEnergy and its subsidiaries.

Under the revolving credit facility, borrowers may request the issuance of letters of credit expiring up to one year from the date of issuance. The stated amount of outstanding letters of credit will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit. Total unused borrowing capability under existing credit facilities and accounts receivable financing facilities totaled $1.96 billion as of June 30, 2005.

The revolving credit facility contains financial covenants, such that each borrower shall maintain a consolidated debt to total capitalization ratio of no more than 0.65 to 1.00. In addition, unless and until FirstEnergy obtains senior unsecured debt ratings of BBB- by S&P or Baa2 by Moody’s, FirstEnergy will maintain a fixed charge ratio of at least 2.00 to 1.00.

As of June 30, 2005, FirstEnergy and it’s subsidiaries’ fixed charge coverage ratios, as defined under the credit agreements, were as follows:

	Debt
	To Total	Fixed Charge
Borrower	Capitalization	Ratio
FirstEnergy	0.55 to 1.00	4.55
OE	0.39 to 1.00	6.66
Penn	0.35 to 1.00	16.97
CEI	0.58 to 1.00	3.82
TE	0.43 to 1.00	3.48
JCP&L	0.31 to 1.00	4.94
Met-Ed	0.38 to 1.00	7.01
Penelec	0.35 to 1.00	5.63

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

FirstEnergy’s regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy’s unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the second quarter of 2005 was 2.93% for the regulated companies’ money pool and 2.86% for the unregulated companies' money pool.

On May 16, 2005, S&P affirmed its 'BBB-' corporate credit ratings on FirstEnergy and its units and revised its outlook on the companies to positive from stable. S&P stated that the rating affirmation and outlook revision reflects the successful restart of the three nuclear units from their respective outages that occurred during the first half of 2005. S&P noted that a subsequent rating upgrade could follow if FirstEnergy's financial performance continues to improve as projected and its nuclear operations further stabilize.

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.

The total principal or par value of optional redemptions during the second quarter of 2005 totaled $110 million with one optional redemption completed following the end of the second quarter as shown in the table below.

Optional Debt and Preferred Stock Redemptions by Company	Date of Redemption		Principal/Par		Annual Cost
			*(In millions)*
CEI		May 1, 2005	$	2		7.000	%
		June 1, 2005		4		7.350	%
JCP&L		May 1, 2005		6		7.125	%
		June 30, 2005		50		8.450	%
Met-Ed		May 1, 2005		7		6.000	%
Penelec		May 1, 2005		3		6.125	%
Penn		May 16, 2005		13		7.625	%
		May 16, 2005		25		7.750	%
			$	110

TE		July 1, 2005	$	30		7.000	%

Cash Flows From Investing Activities

Net cash flows used in investing activities resulted principally from property additions. Regulated services expenditures for property additions primarily include expenditures supporting the distribution of electricity. Capital expenditures by the power supply management services segment are principally generation-related. The following table summarizes the investment activities for the three months and six months ended June 30, 2005 and 2004 by FirstEnergy’s regulated services, power supply management services and other segments:

Summary of Cash Flows	Property
Used for Investing Activities	Additions			Investments			Other			Total
Sources (Uses)	*(In millions)*

Three Months Ended June 30, 2005
Regulated services	$	(158	)	$	(19	)	$	(10	)	$	(187	)
Power supply management services		(66	)		-			-			(66	)
Other		(2	)		3			(6	)		(5	)
Reconciling items		(7	)		(20	)		-			(27	)
Total	$	(233	)	$	(36	)	$	(16	)	$	(285	)

Three Months Ended June 30, 2004
Regulated services	$	(129	)	$	3		$	(5	)	$	(131	)
Power supply management services		(59	)		(2	)		-			(61	)
Other		(1	)		180			2			181
Reconciling items		(8	)		80			-			72
Total	$	(197	)	$	261		$	(3	)	$	61


Six Months Ended June 30, 2005
Regulated services	$	(299	)	$	4		$	(7	)	$	(302	)
Power supply management services		(147	)		(1	)		-			(148	)
Other		(5	)		19			(19	)		(5	)
Reconciling items		(11	)		-			-			(11	)
Total	$	(462	)	$	22		$	(26	)	$	(466	)

Six Months Ended June 30, 2004
Regulated services	$	(220	)	$	(46	)	$	(7	)	$	(273	)
Power supply management services		(103	)		(3	)		-			(106	)
Other		(2	)		173			4			175
Reconciling items		(10	)		53			(19	)		24
Total	$	(335	)	$	177		$	(22	)	$	(180	)

Net cash used for investing activities was $285 million in the second quarter of 2005 compared to $61 million of cash provided from investing activities in the same period of 2004. The change was primarily due to $193 million of lower proceeds from assets sales, a $36 million increase in property additions and an $83 million change in interest rate swap activity. Net cash used for investing activities increased by $286 million in the first six months of 2005 compared to the same period of 2004. The increase principally resulted from lower proceeds from the sale of assets of $150 million, increased property additions of $127 million and a $47 million change in interest rate swap activity, partially offset by the absence of a $51 million NUG trust refund in 2004.

During the second half of 2005, capital requirements for property additions and capital leases are expected to be approximately $622 million, including $24 million for nuclear fuel. FirstEnergy has additional requirements of approximately $41 million for maturing long-term debt during the remainder of 2005. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements.

FirstEnergy’s capital spending for the period 2005-2007 is expected to be about $3.3 billion (excluding nuclear fuel), of which $1.0 billion applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to be approximately $282 million, of which approximately $58 million applies to 2005. During the same period, FirstEnergy’s nuclear fuel investments are expected to be reduced by approximately $284 million and $86 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. Such agreements include contract guarantees, surety bonds, and LOCs. Some of the guaranteed contracts contain ratings contingent collateralization provisions.

As of June 30, 2005, the maximum potential future payments under outstanding guarantees and other assurances totaled $2.4 billion as summarized below:

	Maximum
Guarantees and Other Assurances	Exposure
	*(In millions)*
FirstEnergy guarantees of subsidiaries:
Energy and energy-related contracts ⁽¹⁾	$	897
Other ⁽²⁾		172
		1,069

Surety bonds		296
Letters of credit ⁽³⁾⁽⁴⁾		1,058

Total Guarantees and Other Assurances	$	2,423

⁽¹⁾Issued for a one-year term, with a 10-day termination right by FirstEnergy.
⁽²⁾Issued for various terms.
⁽³⁾Includes $140 million issued for various terms under LOC capacity available
under FirstEnergy's revolving credit agreement and $299 million outstanding in
support of pollution control revenue bonds issued with various maturities.
⁽⁴⁾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 marketing 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 and its subsidiaries to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financings where the law might otherwise limit the counterparties’ claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty’s legal claim to be satisfied by 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-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. The following table summarizes collateral provisions in effect as of June 30, 2005:

	Total		Collateral Paid				Remaining
Collateral Provisions	Exposure		Cash		LOC		Exposure
	*(In millions)*

Credit rating downgrade	$	367	$	141	$	18	$	208
Adverse event		50		-		7		43
Total	$	417	$	141	$	25	$	251

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 provided an LOC ($47 million as of June 30, 2005, which is included in the caption "Other" in the above table of Guarantees and Other Assurances), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.

OFF-BALANCE SHEET ARRANGEMENTS

FirstEnergy has obligations that are not included on its Consolidated Balance Sheet related to the sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are satisfied through the operating lease payments. The present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.3 billion as of June 30, 2005.

FirstEnergy has equity ownership interests in certain various 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 contractual obligations above.

On June 16, 2005, the CFC receivables financing structure was renewed and restructured from an off-balance sheet transaction to an on-balance sheet transaction. Under the new structure, any borrowings under the facility appear on the balance sheet as short-term debt.

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 management oversight to risk management activities throughout the Company.

Commodity Price Risk

FirstEnergy is exposed to market risk primarily due to fluctuating electricity, natural gas, coal, nuclear fuel, emission allowance prices and energy transmission. To manage the volatility relating to these exposures, it 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 and, to a much lesser extent, for trading purposes. All derivatives that fall within the scope of SFAS 133 must be recorded at their fair market value and be marked to market. The majority of FirstEnergy’s derivative hedging contracts qualify for the normal purchases and normal sales under the SFAS 133 exemption and are therefore excluded from the table below. Of those contracts not exempt from such treatment, most are non-trading contracts that do not qualify for hedge accounting treatment. The change in the fair value of commodity derivative contracts related to energy production during the second quarter and first six months of 2005 is summarized in the following table:

	Three Months Ended								Six Months Ended
Increase (Decrease) in the Fair Value	June 30, 2005								June 30, 2005
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 asset at beginning of period	$	55	$	3		$	58		$	62		$	2		$	64
New contract when entered		-		-			-			-			-			-
Additions/change in value of existing contracts		-		(4	)		(4	)		(1	)		2			1
Change in techniques/assumptions		-		-			-			-			-			-
Settled contracts		-		(1	)		(1	)		(7	)		-			(7	)
Sale of retail natural gas contracts		-		-			-			1			(6	)		(5	)
Outstanding net asset at end of period ⁽¹⁾	$	55	$	(2	)	$	53		$	55		$	(2	)	$	53

Non-commodity Net Assets at End of Period:
Interest rate swaps ⁽²⁾		-		12			12			-			12			12
Net Assets - Derivative Contracts at End of Period	$	55	$	10		$	65		$	55		$	10		$	65

Impact of Changes in Commodity Derivative Contracts⁽³⁾
Income Statement effects (pre-tax)	$	-	$	-		$	-		$	-		$	-		$	-
Balance Sheet effects:
Other comprehensive income (pre-tax)	$	-	$	(5	)	$	(5	)	$	-		$	(4	)	$	(4	)
Regulatory liability	$	-	$	-		$	-		$	(7	)	$	-		$	(7	)

⁽¹⁾ Includes $54 million in non-hedge commodity derivative contracts which are offset by a regulatory liability.
⁽²⁾Interest rate swaps are treated as cash flow or fair value hedges. (See Interest Rate Swap Agreements - Fair Value Hedges and Forward
Starting Swap Agreements - Cash Flow Hedges)
⁽³⁾Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions.

Derivatives are included on the Consolidated Balance Sheet as of June 30, 2005 as follows:

Balance Sheet Classification	Non-Hedge			Hedge			Total
	*(In millions)*
Current -
Other assets	$	1		$	2		$	3
Other liabilities		(1	)		(4	)		(5	)

Non-Current -
Other deferred charges		55			24			79
Other non-current liabilities		-			(12	)		(12	)

Net assets	$	55		$	10		$	65

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 derivative contracts by year are summarized in the following table:

Sources of Information -
Fair Value by Contract Year	2005 ⁽¹⁾		2006		2007		2008		2009		Thereafter		Total
	*(In millions)*

Prices actively quoted ⁽²⁾	$	1	$	1	$	-	$	-	$	-	$	-	$	2
Other external sources ⁽³⁾		9		8		10		-		-		-		27
Prices based on models		-		-		-		8		8		8		24
Total ⁽⁴⁾	$	10	$	9	$	10	$	8	$	8	$	8	$	53

⁽¹⁾ For the last two quarters of 2005.
⁽²⁾ Exchange traded.
⁽³⁾ Broker quote sheets.
⁽⁴⁾ Includes $54 million in non-hedge commodity derivative contracts which are offset by a regulatory liability.

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 both FirstEnergy's trading and nontrading 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, 2005. Based on derivative contracts held as of June 30, 2005, an adverse 10% change in commodity prices would decrease net income by approximately $2 million for the next twelve months.

Interest Rate Swap Agreements - Fair Value Hedges

FirstEnergy utilizes fixed-to-floating interest rate swap agreements, as part of its ongoing effort to manage the interest rate risk of 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 second quarter of 2005, FirstEnergy executed no new fixed-for-floating interest rate swaps and unwound swaps with a total notional amount of $350 million (see Note 7). As of June 30, 2005, the debt underlying the $1.4 billion outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 5.54%, which the swaps have effectively converted to a current weighted average variable interest rate of 4.43%.

	June 30, 2005							December 31, 2004
	Notional		Maturity		Fair			Notional		Maturity		Fair
Interest Rate Swaps	Amount		Date		Value			Amount		Date		Value
	*(Dollars in millions)*

Fixed to Floating Rate	$	200		2006	$	(2	)	$	200		2006	$	(1	)
(Fair value hedges)		100		2008		(1	)		100		2008		(1	)
		50		2010		1			100		2010		1
		50		2011		2			100		2011		2
		450		2013		13			400		2013		4
		100		2014		4			100		2014		2
		150		2015		(2	)		150		2015		(7	)
		200		2016		6			200		2016		1
		-		2018		-			150		2018		5
		-		2019		-			50		2019		2
		100		2031		(2	)		100		2031		(4	)
	$	1,400			$	19		$	1,650			$	4

Forward Starting Swap Agreements - Cash Flow Hedges

During the quarter, FirstEnergy entered into several forward starting swap agreements in order to hedge a portion of the consolidated interest rate risk associated with the planned issuance of fixed-rate, long-term debt securities for one or more of its consolidated entities in the fourth quarter of 2006. These derivatives are treated as cash flow hedges, protecting against the risk of changes in the 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. As of June 30, 2005, FirstEnergy had entered into forward starting swaps with an aggregate notional amount of $375 million.

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $976 million and $951 million as of June 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $98 million reduction in fair value as of June 30, 2005.

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, 2005, the largest credit concentration was with one party, currently rated investment grade, that represented 8% of FirstEnergy’s total credit risk. Within its unregulated energy subsidiaries, 99% of credit exposures, net of collateral and reserve, were with investment-grade counterparties as of June 30, 2005.

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 EUOCs 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. All regulatory assets are expected to be recovered from customers under the Companies' respective transition and regulatory plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those operations.

	June 30,		December 31,		Increase
Regulatory Assets*	2005		2004		(Decrease)
	*(In millions)*

OE	$	935	$	1,116	$	(181	)
CEI		902		959		(57	)
TE		330		375		(45	)
JCP&L		2,138		2,176		(38	)
Met-Ed		673		693		(20	)
Penelec		183		200		(17	)
ATSI		17		13		4
Total	$	5,178	$	5,532	$	(354	)

* Penn had net regulatory liabilities of approximately $37 million and $18 million included in Noncurrent
Liabilities on the Consolidated Balance Sheet as of June 30, 2005 and December 31, 2004, respectively.

Regulatory assets by source are as follows:

	June 30,			December 31,			Increase
Regulatory Assets by Source	2005			2004			(Decrease)
	*(In millions)*

Regulatory transition costs	$	4,380		$	4,889		$	(509	)
Customer shopping incentives *		736			612			124
Customer receivables for future income taxes		296			246			50
Societal benefits charge		30			51			(21	)
Loss on reacquired debt		85			89			(4	)
Employee postretirement benefit costs		60			65			(5	)
Nuclear decommissioning, decontamination
and spent fuel disposal costs		(166	)		(169	)		3
Asset removal costs		(361	)		(340	)		(21	)
Property losses and unrecovered plant costs		40			50			(10	)
MISO transmission costs		20			-			20
JCP&L reliability costs		27			-			27
Other		31			39			(8	)
Total	$	5,178		$	5,532		$	(354	)

* The Ohio Companies are deferring customer shopping incentives and interest costs as new regulatory assets in
accordance with the transition and rate stabilization plans. These regulatory assets, totaling $736 million as of
June 30, 2005 (OE - $274 million, CEI - $354 million, TE - $108 million) will be recovered through a surcharge
equal to the RTC rate in effect when the transition costs have been fully recovered. Recovery of the new
regulatory assets will begin at that time and amortization of the regulatory assets for each accounting period
will be equal to the surcharge revenue recognized during that period.

Reliability Initiatives

FirstEnergy is proceeding with the implementation of the recommendations regarding enhancements to regional reliability 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, however, may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy's filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

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. On March 29, 2004, the NJBPU adopted a Memorandum of Understanding (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 a Special Reliability Master 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 (Focused Audit). A Final Order in the Focused Audit docket was issued by the NJBPU on July 23, 2004. On February 11, 2005, JCP&L met with the Ratepayer Advocate to discuss reliability improvements. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.

See Note 14 to the consolidated financial statements for a more detailed discussion of reliability initiatives, including actions by the PPUC, that impact Met-Ed, Penelec and Penn.

Ohio

The Ohio Companies' Rate Stabilization Plan extends current generation prices through 2008, ensuring adequate generation supply at stabilized prices, and continues the Ohio Companies' support of energy efficiency and economic development efforts. On October 1 and October 4, 2004, the OCC and NOAC, respectively, filed appeals with the Supreme Court of Ohio to overturn the June 9, 2004 PUCO order and associated entries on rehearing. Other key components of the Rate Stabilization Plan include the following:

Amortization period for transition costs being recovered through the RTC extends for OE to as late as 2007; CEI to as late as mid-2009 and TE to as late as mid-2008;

Deferral of interest costs on the accumulated customer shopping incentives as new regulatory assets; and

Ability to request increases in generation charges during 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.

New Jersey

The 2003 NJBPU decision on JCP&L's base electric rate proceeding ordered a Phase II proceeding in which the NJBPU would review whether JCP&L is in compliance with current service reliability and quality standards and determine whether the expenditures and projects undertaken by JCP&L to increase its system's reliability are prudent and reasonable for rate recovery. Depending on its assessment of JCP&L's service reliability, the NJBPU could have increased JCP&L’s return on equity to 9.75% or decreased it to 9.25%. On August 15, 2003 and June 1, 2004, JCP&L filed with the NJBPU an interim motion and a supplemental and amended motion for rehearing and reconsideration of the 2003 NJBPU decision, respectively. On July 16, 2004, JCP&L filed the Phase II petition and testimony with the NJBPU, requesting an increase in base rates of $36 million for the recovery of system reliability costs and a 9.75% return on equity. The filing also requested an increase to the MTC deferred balance recovery of approximately $20 million annually.

· An annual increase in distribution revenues of $23 million effective June 1, 2005, associated with the Phase I Order reconsideration;

· An annual increase in distribution revenues of $36 million effective June 1, 2005, related to JCP&L's Phase II Petition;

· An annual reduction in both rates and amortization expense of $8 million, effective June 1, 2005, in anticipation of an NJBPU order regarding JCP&L's request to securitize up to $277 million of its deferred cost balance;

· An increase in JCP&L's authorized return on common equity from 9.5% to 9.75%; and

· A commitment by JCP&L to maintain a target level of customer service reliability with a reduction in JCP&L's authorized return on common equity to its previous level of 9.5% after the target is not met for two consecutive quarters. The authorized return on common equity would then be restored to 9.75% when the target is met for two consecutive quarters.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in New Jersey.

Pennsylvania

On January 12, 2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005, estimated to be approximately $8 million per month.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania.

Transmission

On September 16, 2004, the FERC issued an order that imposed additional obligations on CEI under certain pre-Open Access transmission contracts among CEI and the cities of Cleveland and Painesville, Ohio. Under the FERC's original decision, CEI would have been responsible for a portion of new energy market charges imposed by MISO when its energy markets began in the spring of 2005. CEI filed for rehearing of the order from the FERC on October 18, 2004. On April 15, 2005, the FERC issued an order on rehearing that "carves out" these contracts from the MISO Day 2 market, which became effective April 1, 2005. While the order on rehearing is favorable to CEI, the impact of the FERC decision on CEI is dependent upon many factors, including the arrangements made by the cities for transmission service and MISO's ability to administer the contracts. Accordingly, the impact of this decision cannot be determined at this time.

Environmental Matters

National Ambient Air Quality Standards

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. On March 14, 2005, the EPA finalized a cap-and-trade program to reduce mercury emissions in two phases from coal-fired power plants. Initially, mercury emissions will decline 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. The future cost of compliance with these regulations may be substantial.

W. H. Sammis Plant

Climate Change

Regulation of Hazardous Waste

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

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 concludes, 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 website (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 also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability 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, and therefore FirstEnergy has not accrued a liability as of June 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, that the FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

Three substantially similar actions were filed in various Ohio State courts by plaintiffs seeking to represent customers who allegedly suffered damages as a result of the August 14, 2003 power outages. All three cases were dismissed for lack of jurisdiction and further appeals were unsuccessful. Two of these cases were refiled at the PUCO, one in 2004 and another in 2005. In each, individual complainants��three in one case and four in the other—seek damages related to the outages and also seek to represent others as part of a class action. FirstEnergy has filed responsive pleadings to both cases. The PUCO has dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Both cases are otherwise currently pending further proceedings. In addition to the two cases that were refiled at the PUCO, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages.

Effective July 1, 2005 the NRC oversight panel for Davis-Besse was terminated and Davis-Besse returned to the standard NRC reactor oversight process. At that time, NRC inspections were augmented to include inspections to support the NRC's Confirmatory Order dated March 8, 2004 that was issued at the time of startup and to address an NRC White Finding related to the performance of the emergency sirens.

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. FENOC operates the Perry Nuclear Power Plant, which currently is owned and/or leased by OE, CEI, TE and Penn (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which include owned portions of the plant). On April 4, 2005, the NRC held a public forum 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 Plant operated "in a manner that preserved public health and safety" and met all cornerstone objectives although it remained under the heightened NRC oversight since August 2004. During the public forum and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process, from increased oversight to possible impact to the plant’s operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition.

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

SFAS 154 - "Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3"

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in an income statement. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. FirstEnergy will adopt this Statement effective January 1, 2006.

FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the second period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective no later than the end of fiscal years ending after December 15, 2005. Therefore, FirstEnergy will adopt this Interpretation in the fourth quarter of 2005. FirstEnergy is currently evaluating the effect this Interpretation will have on its financial statements.

SFAS 123(R), "Share-Based Payment"

In December 2004, the FASB issued SFAS 123(R), a revision to SFAS 123, which requires expensing stock options in the financial statements. Important to applying the new standard is understanding how to (1) measure the fair value of stock-based compensation awards and (2) recognize the related compensation cost for those awards. For an award to qualify for equity classification, it must meet certain criteria in SFAS 123(R). An award that does not meet those criteria will be classified as a liability and remeasured each period. SFAS 123(R) retains SFAS 123's requirements on accounting for income tax effects of stock-based compensation. In April 2005, the SEC delayed the effective date of SFAS 123(R) to annual, rather than interim, periods that begin after June 15, 2005. The SEC’s new rule results in a six-month deferral for FirstEnergy and other companies with a fiscal year beginning January 1. Therefore, FirstEnergy will adopt this Statement effective January 1, 2006. The Company will be applying modified prospective application, without restatement of prior interim periods. Any potential cumulative adjustments have not been determined. FirstEnergy uses the Black-Scholes option-pricing model to value options and will continue to do so upon adoption of SFAS 123(R).

EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

FSP 109-1, "Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction and Qualified Production Activities Provided by the American Jobs Creation Act of 2004"

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	*(In thousands)*
STATEMENTS OF INCOME

OPERATING REVENUES	$	716,612		$	718,347		$	1,442,970		$	1,461,642

OPERATING EXPENSES AND TAXES:
Fuel		12,006			13,844			23,922			28,914
Purchased power		227,507			237,826			474,097			487,707
Nuclear operating costs		92,607			74,392			188,260			154,033
Other operating costs		95,589			91,797			178,768			177,157
Provision for depreciation		31,654			30,215			57,706			60,144
Amortization of regulatory assets		109,670			100,124			221,441			213,819
Deferral of new regulatory assets		(39,026	)		(25,167	)		(63,821	)		(44,062	)
General taxes		46,043			39,488			94,121			88,054
Income taxes		91,192			65,787			146,164			127,361
Total operating expenses and taxes		667,242			628,306			1,320,658			1,293,127

OPERATING INCOME		49,370			90,041			122,312			168,515

OTHER INCOME (net of income taxes)		16,860			16,787			17,283			33,144

NET INTEREST CHARGES:
Interest on long-term debt		15,732			16,395			31,341			32,984
Allowance for borrowed funds used during construction
and capitalized interest		(3,006	)		(1,593	)		(5,241	)		(2,974	)
Other interest expense		5,670			4,046			8,264			6,936
Subsidiary's preferred stock dividend requirements		738			640			1,378			1,280
Net interest charges		19,134			19,488			35,742			38,226

NET INCOME		47,096			87,340			103,853			163,433

PREFERRED STOCK DIVIDEND REQUIREMENTS		658			659			1,317			1,220

EARNINGS ON COMMON STOCK	$	46,438		$	86,681		$	102,536		$	162,213

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	47,096		$	87,340		$	103,853		$	163,433

OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gain (loss) on available for sale securities		(12,960	)		(1,021	)		(15,677	)		4,146
Income tax (benefit) related to other comprehensive income		(4,546	)		(421	)		(5,670	)		1,709
Other comprehensive income (loss), net of tax		(8,414	)		(600	)		(10,007	)		2,437

TOTAL COMPREHENSIVE INCOME	$	38,682		$	86,740		$	93,846		$	165,870

The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these
statements.

OHIO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,			December 31,
	2005			2004
	*(In thousands)*
ASSETS
UTILITY PLANT:
In service	$	5,553,362		$	5,440,374
Less - Accumulated provision for depreciation		2,770,924			2,716,851
		2,782,438			2,723,523
Construction work in progress -
Electric plant		226,124			203,167
Nuclear fuel		-			21,694
		226,124			224,861
		3,008,562			2,948,384
OTHER PROPERTY AND INVESTMENTS:
Investment in lease obligation bonds		341,582			354,707
Nuclear plant decommissioning trusts		447,649			436,134
Long-term notes receivable from associated companies		207,430			208,170
Other		45,394			48,579
		1,042,055			1,047,590
CURRENT ASSETS:
Cash and cash equivalents		1,283			1,230
Receivables -
Customers (less accumulated provisions of $6,282,000 and $6,302,000, respectively,
for uncollectible accounts)		282,283			274,304
Associated companies		167,260			245,148
Other (less accumulated provisions of $52,000 and $64,000, respectively,
for uncollectible accounts)		10,549			18,385
Notes receivable from associated companies		598,151			538,871
Materials and supplies, at average cost		108,221			90,072
Prepayments and other		20,324			13,104
		1,188,071			1,181,114
DEFERRED CHARGES:
Regulatory assets		935,223			1,115,627
Property taxes		61,419			61,419
Unamortized sale and leaseback costs		57,670			60,242
Other		67,867			68,275
		1,122,179			1,305,563
	$	6,360,867		$	6,482,651
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity -
Common stock, without par value, authorized 175,000,000 shares - 100 shares outstanding	$	2,099,089		$	2,098,729
Accumulated other comprehensive loss		(57,125	)		(47,118	)
Retained earnings		367,734			442,198
Total common stockholder's equity		2,409,698			2,493,809
Preferred stock		60,965			60,965
Preferred stock of consolidated subsidiary		14,105			39,105
Long-term debt and other long-term obligations		1,104,584			1,114,914
		3,589,352			3,708,793
CURRENT LIABILITIES:
Currently payable long-term debt		289,215			398,263
Short-term borrowings -
Associated companies		82,389			11,852
Other		143,912			167,007
Accounts payable -
Associated companies		100,452			187,921
Other		12,824			10,582
Accrued taxes		172,478			153,400
Other		84,545			74,663
		885,815			1,003,688
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		724,040			766,276
Accumulated deferred investment tax credits		55,800			62,471
Asset retirement obligation		350,387			339,134
Retirement benefits		314,543			307,880
Other		440,930			294,409
		1,885,700			1,770,170
COMMITMENTS AND CONTINGENCIES (Note 13)
	$	6,360,867		$	6,482,651

The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these balance sheets.

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	*(In thousands)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	47,096		$	87,340		$	103,853		$	163,433
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation		31,654			30,215			57,706			60,144
Amortization of regulatory assets		109,670			100,124			221,441			213,819
Deferral of new regulatory assets		(39,026	)		(25,167	)		(63,821	)		(44,062	)
Nuclear fuel and lease amortization		9,493			10,591			18,663			21,852
Amortization of lease costs		(35,982	)		(35,482	)		(2,952	)		(2,452	)
Amortization of electric service obligation		(3,991	)		-			(3,991	)		-
Deferred income taxes and investment tax credits, net		19,485			(20,542	)		(5,142	)		(50,587	)
Accrued retirement benefit obligations		4,627			6,106			6,661			17,229
Accrued compensation, net		850			(372	)		(3,157	)		4,032
Decrease (increase) in operating assets -
Receivables		(8,378	)		127,707			77,745			75,772
Materials and supplies		(2,315	)		(3,104	)		(18,149	)		(5,866	)
Prepayments and other current assets		5,657			5,315			(7,220	)		(6,514	)
Increase (decrease) in operating liabilities -
Accounts payable		(45,373	)		(334,764	)		(85,227	)		(93,785	)
Accrued taxes		(25,370	)		(30,877	)		19,078			(342,454	)
Accrued interest		(7,784	)		(5,553	)		(791	)		(110	)
Prepayment for electric service - education programs		136,142			-			136,142			-
Other		6,357			(11,403	)		18,071			(5,294	)
Net cash provided from (used for) operating activities		202,812			(99,866	)		468,910			5,157

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing -
Long-term debt		146,450			-			146,450			30,000
Short-term borrowings, net		16,260			-			47,442			-
Redemptions and Repayments -
Preferred stock		(37,750	)		-			(37,750	)		-
Long-term debt		(244,721	)		(19,809	)		(260,508	)		(116,810	)
Short-term borrowings, net		-			(94,155	)		-			(77,814	)
Dividend Payments -
Common stock		(130,000	)		(117,000	)		(177,000	)		(171,000	)
Preferred stock		(658	)		(659	)		(1,317	)		(1,220	)
Net cash used for financing activities		(250,419	)		(231,623	)		(282,683	)		(336,844	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(41,675	)		(47,302	)		(121,458	)		(84,963	)
Contributions to nuclear decommissioning trusts		(7,885	)		(7,885	)		(15,770	)		(15,770	)
Loan repayments from (loans to) associated companies, net		95,498			359,878			(58,540	)		408,790
Other		1,748			27,139			9,594			23,411
Net cash provided from (used for) investing activities		47,686			331,830			(186,174	)		331,468

Net increase (decrease) in cash and cash equivalents		79			341			53			(219	)
Cash and cash equivalents at beginning of period		1,204			1,323			1,230			1,883
Cash and cash equivalents at end of period	$	1,283		$	1,664		$	1,283		$	1,664

The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these
statements.

Report of Independent Registered Public Accounting Firm

To the Stockholders 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, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

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, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(G) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 7 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

July 29, 2005

OHIO EDISON COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

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. The OE Companies also provide generation services to those customers electing to retain the OE Companies as their power supplier. The OE Companies provide power directly to wholesale customers under previously negotiated contracts, as well as to some alternative energy suppliers under OE’s transition plan. The OE Companies have unbundled the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Power supply requirements of the OE Companies are provided by FES -- an affiliated company.

Results of Operations

Earnings on common stock in the second quarter of 2005 decreased to $46 million from $87 million in the second quarter of 2004. The decrease in earnings primarily resulted from increases in nuclear operating costs, regulatory asset amortization, general taxes and a one-time income tax charge, which were partially offset by lower purchased power costs and higher regulatory asset deferrals. During the first six months of 2005, earnings on common stock decreased to $103 million from $162 million in the same period of 2004. The decrease in earnings for the first half of 2005 primarily resulted from reduced operating revenues and other income, and increased nuclear operating costs, regulatory asset amortization and the one-time income tax charge. These reductions to earnings were partially offset by decreased fuel and purchased power costs, as well as, increased regulatory asset deferrals.

Operating revenues decreased by $2 million or 0.2% in the second quarter of 2005 compared with the same period in 2004. Lower revenues for the quarter primarily resulted from a $12 million decrease in wholesale sales, partially offset by increases in retail generation and distribution revenues of $6 million and $5 million, respectively. During the first six months of 2005 compared to the same period in 2004, operating revenues decreased by $19 million or 1.3%. Lower revenues for the first half of 2005 were due to a $36 million decrease in wholesale sales, partially offset by increases in retail generation and distribution revenues of $12 million and $7 million, respectively.

Lower wholesale revenues for the second quarter and the first six months of 2005 reflected decreased sales to FES of $22 million (15.7% KWH sales decrease) and $50 million (18.1% KWH sales decrease), respectively, due to reduced nuclear generation available for sale. The decreases in sales to FES were partially offset by increased sales of $10 million and $14 million, respectively, to non-affiliated customers (including MSG sales). Under its Ohio transition plan, OE is required to provide MSG to non-affiliated alternative suppliers (see Outlook - Regulatory Matters).

Increased retail generation revenues for the second quarter of 2005 resulted from increased sales to residential and commercial customers of $7 million and $1 million, respectively, partially offset by a $2 million decrease in sales to industrial customers. The increased generation KWH sales to residential (12.2%) and commercial (2.4%) customers were due to warmer than normal temperatures in the second quarter of 2005 which increased air-conditioning loads. Lower industrial revenues reflected a 6.7% decrease in generation KWH sales, partially offset by higher composite unit prices. The industrial KWH sales decrease resulted from increased customer shopping. Generation services provided to industrial customers by alternative suppliers as a percent of total industrial sales delivered in OE’s service area increased by 2.6 percentage points compared with the second quarter of 2004. Residential and commercial customer shopping remained relatively unchanged.

Retail generation revenues increased for the first six months of 2005 compared to the same period of 2004 in all customer sectors (residential - $5 million, commercial - $4 million and industrial - $3 million). The higher residential and commercial revenues were due to increased generation KWH sales (residential - 3.3% and commercial - 3.2%). The increase in industrial revenues reflected higher composite unit prices ($5 million), partially offset by a 1.6% decrease in generation KWH sales. Similar to the second quarter of 2005, industrial KWH sales decreased principally due to increased customer shopping (2.4 percentage points increase compared with the 2004 period), while residential and commercial customer shopping remained relatively unchanged.

Revenues from distribution throughput increased $5 million in the second quarter of 2005 compared with the same period in 2004. Distribution deliveries to residential customers increased $14 million due to an 11.4% increase in KWH deliveries, partially offset by lower composite unit prices. Distribution revenues from commercial and industrial customers decreased by $3 million and $7 million, respectively, primarily due to lower composite unit prices. Lower unit prices in the commercial sector that reduced revenues by $5 million were partially offset by a 2.4% increase in KWH deliveries; industrial revenues decreased due to lower units prices ($4 million) and a 3.4% decrease in KWH deliveries. Residential and commercial KWH deliveries reflected warmer than normal temperatures in the second quarter of 2005.

Revenues from distribution throughput increased $7 million in the first six months of 2005 compared with the same period in 2004 due to higher revenues from residential customers partially offset by lower commercial and industrial sector revenues. Residential revenues increased $13 million, reflecting a 4.4% increase in KWH deliveries. Commercial distribution revenues declined slightly with lower composite unit prices partially offset by a 3.0% increase in KWH deliveries. Industrial distribution revenues decreased by $6 million reflecting lower composite unit prices, partially offset by a 1.6% increase in KWH distribution deliveries.

Under the Ohio transition plan, OE provides incentives to customers to encourage switching to alternative energy providers. OE’s revenues were reduced by $1 million from additional credits in the second quarter and $4 million in the first six months of 2005 compared to the same periods in 2004. These revenue reductions are deferred for future recovery from customers under OE’s transition plan and do not affect current period earnings (See Regulatory Matters below).

Changes in electric generation sales and distribution deliveries in the second quarter and first six months of 2005 from the corresponding periods of 2004 are summarized in the following table:


Changes in KWH Sales	Three Months			Six Months
Increase (Decrease)
Electric Generation:
Retail		1.6	%		1.4	%
Wholesale		(9.8	)%		(13.6	)%
Total Electric Generation Sales		(4.0	)%		(5.8	)%

Distribution Deliveries:
Residential		11.4	%		4.4	%
Commercial		2.4	%		3.0	%
Industrial		(3.4	)%		1.6	%
Total Distribution Deliveries		2.8	%		3.0	%

Operating Expenses and Taxes

Total operating expenses and taxes increased by $39 million in the second quarter and $28 million in the first six months of 2005 from the same periods of 2004. The following table presents changes from the prior year by expense category.

Operating Expenses and Taxes - Changes	Three Months			Six Months
Increase (Decrease)	*(In millions)*
Fuel costs	$	(2	)	$	(5	)
Purchased power costs		(10	)		(14	)
Nuclear operating costs		18			34
Other operating costs		4			2
Provision for depreciation		1			(2	)
Amortization of regulatory assets		10			8
Deferral of new regulatory assets		(14	)		(20	)
General taxes		7			6
Income taxes		25			19
Net increase in operating expenses and taxes	$	39		$	28

Lower fuel costs in the second quarter and first six months of 2005, compared with the same periods of 2004, resulted from decreased nuclear generation - down 15.7% and 18.1%, respectively. Purchased power costs were lower in both periods of 2005, reflecting lower unit costs and a reduction in KWH purchased in the first half of 2005. KWH purchases were relatively unchanged in the second quarter. Nuclear operating costs increased primarily due to the costs from the Beaver Valley Unit 2 refueling outage (started April 4, 2005) and to a lesser extent from the Perry Unit 1 outage initiated in the first quarter of 2005 that was completed on May 6, 2005. There were no nuclear refueling outages in the same periods last year. The increase in other operating costs in the second quarter and first six months of 2005, compared to the same periods of 2004, resulted primarily from higher vegetation management costs and increased MISO transmission expenses, partially offset by lower employee benefits expenses.

Depreciation in the second quarter of 2005 was relatively unchanged compared to the second quarter of 2004. The decrease in the first six months of 2005 compared with the same period of 2004 was attributable to revised estimated service life assumptions for fossil generating plants. Higher regulatory asset amortization in both periods was primarily due to increased amortization of transition costs being recovered under the Rate Stabilization Plan. Deferral of new regulatory assets decreased expenses by $13 million in both the second quarter and the first six months of 2005 primarily from the PUCO-approved MISO deferrals and related interest beginning in the second quarter of 2005 (see Outlook - Regulatory Matters).

General taxes increased in the second quarter and first six months of 2005 compared to the same periods of 2004, primarily due to the absence of a $6 million Pennsylvania property tax refund recorded in the second quarter of 2004.

Income taxes increased in the second quarter and first six months of 2005 compared to the same periods of 2004, primarily due to the effects of new tax legislation in Ohio (see Note 12 to consolidated financial statements). On June 30, 2005, the State of Ohio enacted new tax legislation that creates a new Commercial Activity Tax (CAT), which is based on qualifying "taxable gross receipts" and will not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax is effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and personal property tax is phased-out over a four-year period at a rate of approximately 25%, annually beginning with the year ended 2005. During the phase-out period the Ohio income tax will be computed consistently with the prior tax law, except that the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period.

As a result of the new tax structure, all net deferred tax benefits that are not expected to reverse during the five-year phase-in period were written-off as of June 30, 2005. Accordingly, OE’s income tax expense increased by $36 million for the three and six-month periods ended June 30, 2005. Income tax expense was reduced during the three and six-month periods ended June 30, 2005 by approximately $5 million by the initial phase-out of the Ohio income tax.

Other Income

Other income decreased $16 million in the first six months of 2005 compared with the same period of 2004, primarily due to an $8.5 million civil penalty payable to the Department of Justice and a $10 million liability for environmental projects recognized in connection with the Sammis Plant settlement (see Outlook - Environmental Matters).

Net Interest Charges

Net interest charges continued to trend lower, decreasing by $0.4 million in the second quarter and $2 million in the first six months of 2005 compared with the same periods of 2004, reflecting $200 million of debt redemptions since July 1, 2004.

Capital Resources and Liquidity

OE’s cash requirements in 2005 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing OE’s net debt and preferred stock outstanding. Available borrowing capacity under credit facilities will be used to manage working capital requirements. Thereafter, OE expects to use a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

As of June 30, 2005, OE's cash and cash equivalents of approximately $1 million remained unchanged from its December 31, 2004 balance.

Cash Flows From Operating Activities

Cash provided from operating activities during the second quarter and first six months of 2005, compared with the corresponding periods in 2004 were as follows:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
Operating Cash Flows	2005		2004			2005		2004
	*(In millions)*

Cash earnings ^(*)	$	144	$	153		$	329	$	383
Working capital and other		59		(253	)		140		(378	)
Total cash flows form operating activities	$	203	$	(100	)	$	469	$	5

^(*) Cash earnings is a non-GAAP measure (see reconciliation below).

Cash earnings, as disclosed in the table above, are not a measure of performance calculated in accordance with GAAP. OE believes that cash earnings is a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Reconciliation of Cash Earnings	2005		2004		2005		2004
	*(In millions)*

Net income (GAAP)	$	47	$	87	$	104	$	163
Non-cash charges (credits):
Provision for depreciation		32		30		58		60
Amortization of regulatory assets		110		100		221		214
Amortization of lease costs		(36)		(35)		(3)		(2)
Nuclear fuel and capital lease amortization		9		11		19		22
Deferral of new regulatory assets		(39)		(25)		(64)		(44)
Deferred income taxes and investment tax credits, net		19		(21)		(5)		(51)
Other non-cash items		2		6		(1)		21
Cash earnings (Non-GAAP)	$	144	$	153	$	329	$	383

Net cash from operating activities increased $303 million in the second quarter of 2005, compared with the second quarter of 2004, due to a $312 million increase from changes in working capital, partially offset by a $9 million decrease in cash earnings as described above and under "Results from Operations". The increase in working capital primarily reflects net changes in accounts payable and accounts receivable to associated companies of $152 million and $136 million of funds received for prepaid electric service under the Energy for Education program.

Net cash from operating activities increased $464 million in the first six months of 2005, compared with the same period in 2004, due to a $518 million increase from changes in working capital, partially offset by a $54 million decrease in cash earnings as described above and under "Results from Operations". The increase in working capital primarily reflects changes in accrued taxes of $362 million and $136 million of funds received for the Energy for Education program. The accrued taxes change includes a $249 million reallocation of tax liabilities among the FirstEnergy subsidiaries pursuant to the tax sharing agreement in the first quarter of 2004.

Cash Flows From Financing Activities

Net cash used for financing activities increased to $250 million in the second quarter of 2005 from $232 million in the second quarter of 2004. The increase primarily resulted from a $13 million increase in common stock dividends to FirstEnergy and a $6 million increase in net debt and preferred stock redemptions. Net cash used for financing activities decreased to $283 million in the first six months of 2005 from $337 million in the same period of 2004. The decrease was due to a $60 million decrease in net debt and preferred stock redemptions, partially offset by a $6 million increase in common stock dividends to FirstEnergy.

On May 16, 2005, Penn redeemed all 127,500 outstanding shares of 7.625% preferred stock at $102.29 per share and all 250,000 outstanding shares of 7.75% preferred stock at $100 per share, including accrued dividends to the date of redemption.

OE had approximately $599 million of cash and temporary cash investments (which include short-term notes receivable from associated companies) and $226 million of short-term indebtedness as of June 30, 2005. OE has authorization from the PUCO to incur short-term debt of up to $500 million (including bank facilities and the utility money pool described below). Penn has authorization from the SEC to incur short-term debt up to its charter limit of $49 million (including the utility money pool). In addition, Penn Power Funding LLC (Penn Funding), a wholly owned subsidiary of Penn, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Penn. Penn Funding can borrow up to $25 million under a receivables financing arrangement. As a separate legal entity with separate creditors, Penn Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Penn. As of June 30, 2005, the facility was drawn for $20 million. On July 15, 2005, the facility was renewed until June 29, 2006. The annual facility fee is 0.25% on the entire finance limit.

On April 6, 2004, Ohio Air Quality Development Authority and Ohio Water Development Authority pollution control bonds aggregating $100 million and $6.45 million, respectively, were refunded by OE. The new bonds were issued in a Dutch Auction interest rate mode, insured with municipal bond insurance and secured by FMB.

On July 1, 2005, Ohio Water Development Authority pollution control bonds aggregating $40 million were refunded by OE. The new bonds were issued in a Dutch Auction interest rate mode, insured with municipal bond insurance. OE provided FMB collateral to the bond insurer.

OE and Penn had the aggregate capability to issue approximately $1.8 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 is also subject to provisions of its 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 to incur additional secured debt not otherwise permitted by a specified exception of up to $668 million as of June 30, 2005. Based upon applicable earnings coverage tests in their respective charters, OE and Penn could issue a total of $2.5 billion of preferred stock (assuming no additional debt was issued) as of June 30, 2005.

On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered into a syndicated $2 billion five-year revolving credit facility. Borrowings under the facility are available to each Borrower separately and will mature on the earlier of 364 days from the date of borrowing and the commitment termination date, as the same may be extended. OE's and Penn’s borrowing limits under the facility are $550 million. The facility replaced FirstEnergy’s $375 million and $1 billion three-year credit agreements and OE’s $125 million three-year credit agreement, as well as OE’s recently-expired $250 million two-year credit agreement.

OE and Penn have the ability to borrow from their regulated affiliates and FirstEnergy to meet their short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount, 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 second quarter of 2005 was 2.93%.

OE’s access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy. The ratings outlook from the rating agencies on all such securities is positive.

On May 16, 2005, S&P affirmed its 'BBB-' corporate credit ratings on FirstEnergy Corp. and its units and revised its outlook on the companies to positive from stable. S&P stated that the rating affirmation and outlook revision reflects the successful restart of the three nuclear units from their respective outages that occurred during the first half of 2005. S&P noted that a subsequent rating upgrade could follow if FirstEnergy's financial performance continues to improve as projected and as its nuclear operations further stabilize.

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s rating outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in its outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.

Cash Flows From Investing Activities

Net cash provided from investing activities totaled $48 million in the second quarter of 2005 compared with $332 million for the same period in 2004. The $284 million change for the second quarter resulted primarily from a $264 million decrease in loan repayments from associated companies and a decrease in property additions. During the first six months of 2005, net cash used for investing activities totaled $186 million compared to net cash provided from investing activities of $331 million in the same period of 2004. The $518 million change resulted primarily from a $467 million position change from receiving loan repayments from associated companies in 2004 to issuing loans to associated companies in 2005, and a $36 million increase in property additions.

During the second half of 2005, capital requirements for property additions and capital leases are expected to be approximately $133 million, including $17 million for nuclear fuel. OE has additional requirements of approximately $24 million to meet sinking fund requirements for preferred stock and maturing long-term debt (excluding Penn’s optional redemptions disclosed above) during the remainder of 2005. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements.

OE’s capital spending for the period 2005-2007 is expected to be about $667 million (excluding nuclear fuel), of which approximately $218 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to be approximately $147 million, of which about $35 million applies to 2005. During the same period, its nuclear fuel investments are expected to be reduced by approximately $129 million and $40 million, respectively, as the nuclear fuel is consumed.

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. The present value of these operating lease commitments, net of trust investments, was $663 million as of June 30, 2005.

Equity Price Risk

Included in OE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $251 million and $248 million as of June 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $25 million reduction in fair value as of June 30, 2005. Changes in the fair value of these investments are recorded in OCI unless recognized as a result of a sale or recognized as regulatory assets or liabilities.

Outlook

The electric industry continues to transition to a more competitive environment and all of the OE Companies’ customers can select alternative energy suppliers. The OE Companies continue to deliver power to residential homes and businesses through their existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. In Ohio and Pennsylvania, the OE Companies have a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties.

FirstEnergy Intra-System Generation Asset Transfers

On May 13, 2005, Penn, and on May 18, 2005, OE, CEI and TE, entered into certain agreements described below (Agreements) implementing a series of intra-system generation asset transfers. When concluded, the asset transfers will result in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear, fossil and hydroelectric plants being owned by NGC, and FGCO, respectively. The generating plant interests that are being transferred do not include leasehold interests of CEI, TE and OE in plants that are currently subject to sale and leaseback arrangements with non-affiliates.

Regulatory Matters

In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of OE's customers elects to obtain power from an alternative supplier, OE reduces the customer's bill with a "generation shopping credit," based on the generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. OE has continuing PLR responsibility to its franchise customers through December 31, 2008 unless the PUCO accepts future competitive bid results prior to the end of that period under the revised Rate Stabilization Plan. As part of OE's transition plan, it is obligated to supply electricity to customers who do not choose an alternative supplier. OE is also required to provide 560 MW of low cost supply (MSG) to unaffiliated alternative suppliers who serve customers within its service area. FES acts as an alternate supplier for a portion of the load in OE's franchise area.

OE's Rate Stabilization Plan extends current generation prices through 2008, ensuring adequate generation supply at stabilized prices, and continues OE's support of energy efficiency and economic development efforts. On October 1 and October 4, 2004, the OCC and NOAC, respectively, filed appeals with the Supreme Court of Ohio to overturn the June 9, 2004 PUCO order and associated entries on rehearing. Other key components of the Rate Stabilization Plan include the following:

Amortization period for transition costs being recovered through the RTC for OE extends to as late as 2007;

Deferral of interest costs on the accumulated customer shopping incentives as new regulatory assets; and

Ability to request increases in generation charges during 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes.

On May 27, 2005, OE filed an application with the PUCO to establish a generation rate adjustment rider under the Rate Stabilization Plan. The application seeks to implement recovery of increased fuel costs from 2006 through 2008 applicable to OE’s retail customers through a tariff rider to be implemented January 1, 2006. The application reflects projected increases in fuel costs in 2006 compared to 2002 baseline costs. The new rider is seeking to recover all costs above the baseline. Various parties including the OCC have intervened in this case. OE has received discovery requests from the OCC and the PUCO staff. A procedural schedule has been established by the PUCO, with a hearing scheduled for October 4, 2005.

On December 9, 2004, the PUCO rejected the auction price results from a required competitive bid process and issued an entry stating that the pricing under the approved Rate Stabilization Plan will take effect on January 1, 2006. The PUCO may require OE to undertake, no more often than annually, a similar competitive bid process to secure generation for the years 2007 and 2008. On July 22, 2005, FirstEnergy filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approved by the PUCO for OE in 2004. Any acceptance of future competitive bid results would terminate the Rate Stabilization Plan pricing, but not the related approved accounting, and not until twelve months after the PUCO authorizes such termination.

On December 30, 2004, OE filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application seeks recovery of these costs beginning January 1, 2006. At the time of filing the application, these costs were estimated to be approximately $14 million per year; however, OE anticipates that this amount will increase. OE requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted thereafter each July 1. OE reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only other party in this proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This settlement, which was filed with the PUCO on July 22, 2005, provides for the rider recovery requested by OE, with carrying charges applied in the subsequent year’s rider for any over or under collection while the then-current rider is in effect. If the settlement stipulation is approved by the PUCO, the actual amounts to be recovered through the January 1, 2006 rider will be submitted to the PUCO on or before November 1, 2005.

The second application seeks authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for OE to defer incremental transmission and ancillary service-related charges incurred as a participant in the MISO, but only for those costs incurred during the period December 30, 2004, through December 31, 2005. Deferral of all costs incurred prior to December 31, 2004 was denied. The PUCO also authorized OE to accrue carrying charges on the deferred balances. An application filed with the PUCO to recover these deferred charges over a five-year period through the rider, beginning in 2006, is pending. The OCC, OPAE and OE each filed applications for rehearing. OE sought authority to defer the transmission and ancillary service related costs incurred during the period October 1, 2003 through December 29, 2004, while both OCC and OPAE sought to have the PUCO deny deferral of all costs. On July 6, 2005, the PUCO denied OE's and OCC’s applications and, at the request of OE, struck as untimely OPAE’s application. OE and the OCC have sixty days from that date to file a notice of appeal with the Ohio Supreme Court.

OE and Penn record as regulatory assets costs which have been authorized by the PUCO, the PPUC and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. OE’s regulatory assets as of June 30, 2005 and December 31, 2004, were $0.9 billion and $1.1 billion, respectively. OE is deferring customer shopping incentives and interest costs as new regulatory assets in accordance with its transition and rate stabilization plans. These regulatory assets total $274 million as of June 30, 2005 and will be recovered through a surcharge rate equal to the RTC rate in effect when the transition costs have been fully recovered. Recovery of the new regulatory assets will begin at that time and amortization of the regulatory assets for each accounting period will be equal to the surcharge revenue recognized during that period. Penn's net regulatory asset components aggregate as net regulatory liabilities of approximately $37 million and $18 million, and are included in Other Noncurrent Liabilities on the Consolidated Balance Sheet as of June 30, 2005 and December 31, 2004, respectively.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio and Pennsylvania and a more detailed discussion of reliability initiatives, including actions by the PPUC, that impact Penn.

Environmental Matters

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

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including 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 nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR will require 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). The OE Companies’ Ohio and Pennsylvania fossil-fuel generation facilities will be subject to the caps on SO₂ and 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 SO₂emissions 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 the OE Companies operate 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. On March 14, 2005, the EPA finalized a cap-and-trade program to reduce mercury emissions in two phases from coal-fired power plants. Initially, mercury emissions will decline 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. The future cost of compliance with these regulations may be substantial.

W. H. Sammis Plant

Climate Change

The OE Companies cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO₂ emissions could require significant capital and other expenditures. However, the CO₂ emissions per KWH of electricity generated by the OE Companies is lower than many regional competitors due to the OE Companies' diversified generation sources which include low or non-CO₂emitting gas-fired and nuclear generators.

Regulation of Hazardous Waste

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to OE's normal business operations pending against OE and its subsidiaries. The most significant are described below.

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 concludes, 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 website (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 also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability 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, and therefore FirstEnergy has not accrued a liability as of June 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, that the FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

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. FENOC operates the Perry Nuclear Power Plant, in which the OE Companies have a 35.24% interest (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which will include owned portions of the plant). On April 4, 2005, the NRC held a public forum 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 Plant operated "in a manner that preserved public health and safety" and met all cornerstone objectives although it remained under the heightened NRC oversight since August 2004. During the public forum and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process from increased oversight to possible impact to the plant’s operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition.

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and OE, and the Davis-Besse extended outage (OE has no interest in Davis-Besse), have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.

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

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

SFAS 154 - "Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3"

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in an income statement. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. OE will adopt this Statement effective January 1, 2006.

FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the second period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective no later than the end of fiscal years ending after December 15, 2005. Therefore, OE will adopt this Interpretation in the fourth quarter of 2005. OE is currently evaluating the effect this standard will have on its financial statements.

EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In March 2004, the EITF reached a consensus on the application guidance for Issue 03-1. EITF 03-1 provides a model for determining when investments in certain debt and equity securities are considered other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair value and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective for periods beginning after June 15, 2004, were delayed indefinitely by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, OE continues to evaluate its investments as required by existing authoritative guidance.

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	*(In thousands)*
STATEMENTS OF INCOME

OPERATING REVENUES	$	448,747		$	440,876		$	881,920		$	867,411

OPERATING EXPENSES AND TAXES:
Fuel		21,110			19,376			39,437			36,572
Purchased power		138,842			136,505			281,726			271,182
Nuclear operating costs		36,786			18,521			95,513			51,236
Other operating costs		74,711			79,634			138,284			143,661
Provision for depreciation		33,387			32,776			64,502			64,964
Amortization of regulatory assets		55,016			50,022			109,042			98,090
Deferral of new regulatory assets		(40,701	)		(32,956	)		(65,989	)		(51,436	)
General taxes		36,605			34,480			75,492			73,298
Income taxes		34,734			25,161			39,611			29,174
Total operating expenses and taxes		390,490			363,519			777,618			716,741

OPERATING INCOME		58,257			77,357			104,302			150,670

OTHER INCOME (net of income taxes)		9,270			9,494			13,574			21,221

NET INTEREST CHARGES:
Interest on long-term debt		28,410			36,695			56,362			68,906
Allowance for borrowed funds used during construction		(1,294	)		(1,015	)		(883	)		(2,726	)
Other interest expense		1,742			1,446			8,256			7,511
Net interest charges		28,858			37,126			63,735			73,691

NET INCOME		38,669			49,725			54,141			98,200

PREFERRED STOCK DIVIDEND REQUIREMENTS		-			1,755			2,918			3,499

EARNINGS ON COMMON STOCK	$	38,669		$	47,970		$	51,223		$	94,701

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	38,669		$	49,725		$	54,141		$	98,200

OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized loss on available for sale securities		(1,349	)		(10,371	)		(2,570	)		(2,323	)
Income tax benefit related to other comprehensive income		419			4,248			923			952
Other comprehensive income (loss), net of tax		(930	)		(6,123	)		(1,647	)		(1,371	)

TOTAL COMPREHENSIVE INCOME	$	37,739		$	43,602		$	52,494		$	96,829

The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an
integral part of these statements.

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,		December 31,
	2005		2004
	*(In thousands)*
ASSETS
UTILITY PLANT:
In service	$	4,497,877	$	4,418,313
Less - Accumulated provision for depreciation		2,000,871		1,961,737
		2,497,006		2,456,576
Construction work in progress -
Electric plant		79,897		85,258
Nuclear fuel		4,330		30,827
		84,227		116,085
		2,581,233		2,572,661
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes		564,172		596,645
Nuclear plant decommissioning trusts		401,610		383,875
Long-term notes receivable from associated companies		7,546		97,489
Other		15,945		17,001
		989,273		1,095,010
CURRENT ASSETS:
Cash and cash equivalents		207		197
Receivables-
Customers (less accumulated provision of $4,510,000 for uncollectible accounts in 2005)		255,422		11,537
Associated companies		29,279		33,414
Other (less accumulated provisions of $19,000 and $293,000, respectively,
for uncollectible accounts)		11,109		152,785
Notes receivable from associated companies		23,537		521
Materials and supplies, at average cost		87,713		58,922
Prepayments and other		1,948		2,136
		409,215		259,512
DEFERRED CHARGES:
Goodwill		1,693,629		1,693,629
Regulatory assets		902,137		958,986
Property taxes		77,792		77,792
Other		36,471		32,875
		2,710,029		2,763,282
	$	6,689,750	$	6,690,465
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 105,000,000 shares -
79,590,689 shares outstanding	$	1,356,983	$	1,281,962
Accumulated other comprehensive income		16,212		17,859
Retained earnings		480,957		553,740
Total common stockholder's equity		1,854,152		1,853,561
Preferred stock		-		96,404
Long-term debt and other long-term obligations		1,948,083		1,970,117
		3,802,235		3,920,082
CURRENT LIABILITIES:
Currently payable long-term debt		75,694		76,701
Short-term borrowings-
Associated companies		404,290		488,633
Other		155,000		-
Accounts payable-
Associated companies		191,959		150,141
Other		5,733		9,271
Accrued taxes		122,675		129,454
Accrued interest		21,782		22,102
Lease market valuation liability		60,200		60,200
Other		43,841		61,131
		1,081,174		997,633
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		543,554		540,211
Accumulated deferred investment tax credits		58,241		60,901
Asset retirement obligation		281,206		272,123
Retirement benefits		84,428		82,306
Lease market valuation liability		638,100		668,200
Other		200,812		149,009
		1,806,341		1,772,750
COMMITMENTS AND CONTINGENCIES (Note 13)
	$	6,689,750	$	6,690,465

The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are
an integral part of these balance sheets.

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	*(In thousands)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	38,669		$	49,725		$	54,141		$	98,200
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation		33,387			32,776			64,502			64,964
Amortization of regulatory assets		55,016			50,022			109,042			98,090
Deferral of new regulatory assets		(40,701	)		(32,956	)		(65,989	)		(51,436	)
Nuclear fuel and capital lease amortization		6,171			7,509			10,781			12,616
Amortization of electric service obligation		(4,672	)		(4,818	)		(10,123	)		(9,541	)
Deferred rents and lease market valuation liability		(222	)		(223	)		(53,691	)		(41,858	)
Deferred income taxes and investment tax credits, net		8,956			2,412			4,450			(1,627	)
Accrued retirement benefit obligations		2,600			2,314			2,122			8,046
Accrued compensation, net		230			476			(2,495	)		1,929
Decrease (increase) in operating assets-
Receivables		(182,964	)		(33,923	)		(98,074	)		109,843
Materials and supplies		(6,455	)		(3,118	)		(28,791	)		(5,473	)
Prepayments and other current assets		(439	)		2			188			1,897
Increase (decrease) in operating liabilities-
Accounts payable		(958	)		(80,735	)		38,280			(58,348	)
Accrued taxes		14,419			31,061			(6,779	)		(36,865	)
Accrued interest		(12,351	)		(7,392	)		(320	)		847
Prepayment for electric service - education programs		67,589			-			67,589			-
Other		(4,513	)		(7,070	)		(7,871	)		(36,858	)
Net cash provided from (used for) operating activities		(26,238	)		6,062			76,962			154,426

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		53,284			-			53,284			80,908
Short-term borrowings, net		88,557			101,255			58,874			-
Equity contributions from parent		75,000			-			75,000			-
Redemptions and Repayments-
Preferred stock		(4,000	)		-			(101,900	)		-
Long-term debt		(56,600	)		(175	)		(56,930	)		(8,101	)
Short-term borrowings, net		-			-			-			(80,912	)
Dividend Payments-
Common stock		(69,000	)		(90,000	)		(124,000	)		(145,000	)
Preferred stock		-			(1,754	)		(2,260	)		(3,498	)
Net cash provided from (used for) financing activities		87,241			9,326			(97,932	)		(156,603	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(26,561	)		(20,861	)		(60,244	)		(38,729	)
Loan repayments from (loans to) associated companies, net		(23,861	)		13,736			66,927			10,814
Investments in lessor notes		3			-			32,473			20,965
Contributions to nuclear decommissioning trusts		(7,256	)		(7,256	)		(14,512	)		(14,512	)
Other		(3,328	)		(1,007	)		(3,664	)		(943	)
Net cash provided from (used for) investing activities		(61,003	)		(15,388	)		20,980			(22,405	)

Net increase (decrease) in cash and cash equivalents		-			-			10			(24,582	)
Cash and cash equivalents at beginning of period		207			200			197			24,782
Cash and cash equivalents at end of period	$	207		$	200		$	207		$	200

The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an
integral part of these statements.

Report of Independent Registered Public Accounting Firm

To the Stockholders 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, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

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, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(G) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 6 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

July 29, 2005

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in portions of Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain CEI as their power supplier. CEI provides power directly to alternative energy suppliers under CEI’s transition plan. CEI has unbundled the price of electricity into its component elements -- including generation, transmission, distribution and transition charges. Power supply requirements of CEI are provided by FES -- an affiliated company.

Results of Operations

Earnings on common stock in the second quarter of 2005 decreased to $39 million from $48 million in the second quarter of 2005. For the first six months of 2005, earnings on common stock decreased to $51 million from $95 million in the same period of 2004. The decrease in earnings in both 2005 periods primarily resulted from increases in nuclear operating costs, purchased power costs, regulatory asset amortization and a one-time income tax charge, which were partially offset by higher operating revenues, increased regulatory asset deferrals and lower net interest charges.

Operating revenues increased by $8 million or 1.8% in the second quarter of 2005 from the same period in 2004. Higher revenues for the quarter primarily resulted from increases in retail generation and distribution revenues of $4 million and $10 million, respectively, partially offset by a $3 million decrease in revenues from wholesale sales. During the first six months of 2005 compared to the same period in 2004, operating revenues increased by $15 million or 1.7%. Higher revenues for the first half of 2005 were due to increases in retail generation and distribution revenues of $10 million and $5 million, respectively, partially offset by a $3 million reduction in revenues from wholesale sales.

Increased retail generation revenues for the second quarter and first six months of 2005 resulted from higher commercial and industrial unit prices, and higher residential KWH sales, partially offset by lower industrial KWH sales. A 16.8% increase in residential KWH sales during the second quarter was primarily due to warmer weather in CEI's service area, as compared to last year. A decrease in residential customer shopping by 4.1 percentage points in the second quarter and 2.1 percentage points in the first six months of 2005 also contributed to the higher generation KWH sales for each period as compared to 2004.

Revenue from wholesale sales decreased by $3 million during the second quarter of 2005, reflecting the effect of a 7.5% net decrease in KWH sales. Under its Ohio transition plan, CEI is required to provide MSG to non-affiliated alternative suppliers (see Outlook - Regulatory Matters). Sales to FES decreased by $12 million (10.6% KWH decrease) due to a decrease in nuclear generation available for sale. The decrease in sales to FES was partially offset by a $9 million increase in MSG sales to non-affiliated wholesale customers (29.7% KWH increase) during the second quarter of 2005. In the first six months of 2005, wholesale sales revenue decreased by $3 million, reflecting the effect of a 5.4% net decrease in KWH sales. A decrease in sales to FES of $20 million (8.9% KWH decrease) was partially offset by a $17 million increase (33.9% KWH increase) in MSG sales to non-affiliated wholesale customers.

Revenues from distribution throughput increased $10 million in the second quarter of 2005 compared with the same quarter of 2004. The increase was due to higher residential and commercial revenues ($13 million and $3 million, respectively), reflecting increased distribution deliveries in the second quarter of 2005, in part due to warmer weather. These increases were partially offset by lower industrial revenues of $6 million as a result of lower unit prices and decreases in KWH sales.

Revenues from distribution throughput increased $5 million in the first six months of 2005 compared with the same period in 2004 due to higher revenues in the residential ($9 million) and commercial ($5 million) sectors, partially offset by lower industrial revenues ($9 million). Higher distribution deliveries in the residential and commercial sectors were partially offset by lower unit prices and decreases in KWH sales in the industrial sector.

Changes in electric generation sales and distribution deliveries in the second quarter and first six months of 2005 from the corresponding periods of 2004 are summarized in the following table:

	Three			Six
Changes in KWH Sales	Months			Months
Increase (Decrease)
Electric Generation:
Retail		(0.9	)%		(0.8	)%
Wholesale		(7.5	)%		(5.4	)%
Total Electric Generation Sales		(4.8	)%		(3.4	)%

Distribution Deliveries:
Residential		16.8	%		5.0	%
Commercial		3.1	%		4.3	%
Industrial		(3.4	)%		(2.9	)%
Total Distribution Deliveries		3.0	%		1.0	%

Operating Expenses and Taxes

Total operating expenses and taxes increased by $27 million in the second quarter and $61 million in the first six months of 2005 from the same periods of 2004. The following table presents changes from the prior year by expense category.


	Three			Six
Operating Expenses and Taxes - Changes	Months			Months
Increase (Decrease)	*(In millions)*
Fuel costs	$	2		$	3
Purchased power costs		2			10
Nuclear operating costs		18			44
Other operating costs		(5	)		(5	)
Provision for depreciation		1			-
Amortization of regulatory assets		5			11
Deferral of new regulatory assets		(8	)		(15	)
General taxes		2			2
Income taxes		10			11
Net increase in operating expenses and taxes	$	27		$	61

Higher purchased power costs in the second quarter of 2005, compared with the second quarter of 2004, reflected higher unit costs, partially offset by lower KWH purchased. Higher purchased power costs in the first six months of 2005 compared to the same period last year reflected both higher unit costs and higher KWH purchased. The increase in nuclear operating costs in the second quarter and first six months of 2005, compared to the same periods of 2004, was primarily due to a refueling outage (including an unplanned extension) at the Perry Plant and a refueling outage at Beaver Valley Unit 2. A mid-cycle inspection outage at the Davis-Besse Plant in the first quarter of 2005 also contributed to higher nuclear operating costs in the first six months of 2005. There were no scheduled outages in the first six months of 2004.

Higher regulatory asset amortization in the second quarter and first six months of 2005, compared to the same periods last year, was primarily due to increased amortization of transition costs being recovered under the Rate Stabilization Plan. Increases in regulatory asset deferrals for both the second quarter and first six months in 2005 as compared to the same periods in 2004 resulted from higher shopping incentive deferrals and related interest, and the PUCO-approved MISO cost deferrals, including interest, beginning in the second quarter of 2005 (see Outlook - Regulatory Matters).

On June 30, 2005, the State of Ohio enacted new tax legislation that creates a new Commercial Activity Tax (CAT), which is based on qualifying "taxable gross receipts" and will not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax is effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and personal property tax is phased-out over a four-year period at a rate of 25% annually, beginning with the year ended 2005. For example, during the phase-out period the Ohio income-based franchise tax will be computed consistently with prior tax law, except that the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period. As a result of the new tax structure, all net deferred tax benefits that are not expected to reverse during the five-year phase-in period were written-off as of June 30, 2005. The impact on income taxes associated with the required adjustment to net deferred taxes for the second quarter of 2005 was additional tax expense of approximately $8 million, which was partially offset by the phase-out of the Ohio income tax which reduced income taxes by approximately $1 million in the second quarter of 2005. See Note 12 to the consolidated financial statements.

Net Interest Charges

Net interest charges continued to trend lower, decreasing by $8 million in the second quarter and $10 million in the first six months of 2005 from the same periods last year, reflecting the effects of redemptions and refinancings of $286 million and $100 million, respectively, since July 1, 2004.

Capital Resources and Liquidity

CEI’s cash requirements in 2005 for operating expenses, construction expenditures and scheduled debt maturities are expected to be met without increasing net debt. Thereafter, CEI expects to use a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

As of June 30, 2005, CEI had $207,000 of cash and cash equivalents, compared with $197,000 as of December 31, 2004. The major sources of changes in these balances are summarized below.

Cash Flows from Operating Activities

Cash provided by operating activities during the second quarter and first six months of 2005, compared with the corresponding periods in 2004, were as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Operating Cash Flows	2005			2004			2005			2004
	*(In millions)*

Cash earnings ^(*)	$	100		$	107		$	113		$	179
Working capital and other		(126	)		(101	)		(36	)		(25	)
Total cash flows form operating activities	$	(26	)	$	6		$	77		$	154

^(*) Cash earnings is a non-GAAP measure (see reconciliation below).

Cash earnings (in the table above) are not a measure of performance calculated in accordance with GAAP. CEI believes that cash earnings is a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Reconciliation of Cash Earnings	2005			2004			2005			2004
	*(In millions)*

Net income (GAAP)	$	39		$	50		$	54		$	98
Non-cash charges (credits):
Provision for depreciation		34			33			65			65
Amortization of regulatory assets		55			50			109			98
Deferral of new regulatory assets		(41	)		(33	)		(66	)		(51	)
Nuclear fuel and capital lease amortization		7			8			11			13
Amortization of electric service obligation		(5	)		(6	)		(10	)		(10	)
Deferred rents and lease market valuation liability		(1	)		-			(54	)		(42	)
Deferred income taxes and investment tax credits, net		9			2			5			(2	)
Accrued retirement benefit obligations		3			2			2			8
Accrued compensation, net		-			1			(3	)		2
Cash earnings (Non-GAAP)	$	100		$	107		$	113		$	179

The decrease in cash earnings of $7 million for the second quarter and $66 million for the first six months of 2005, as compared to the respective periods of 2004, are described above under "Results of Operations". The largest factors contributing to the changes in working capital and other operating cash flows for the second quarter and first six months of 2005 are increases in accounts receivable related to the conversion of the CFC receivables financing ($155 million) to on-balance sheet transactions, offset in part by funds received for prepaid electric service under the Energy for Education Program and changes in accounts payable.

Cash Flows from Financing Activities

Net cash provided from financing activities increased $78 million in the second quarter of 2005 from the second quarter of 2004. The increase resulted from a $75 million equity contribution from FirstEnergy and lower common stock dividends to FirstEnergy of $21 million, partially offset by a $20 million increase in net debt redemptions.

Net cash used for financing activities decreased $59 million in the first six months of 2005 from the same period last year. The decrease resulted from a $75 million equity contribution from FirstEnergy in the second quarter of 2005, lower common stock dividends to FirstEnergy and an increase in short-term financing, partially offset by an increase in preferred stock redemptions.

CEI had $207,000 of cash and temporary investments and approximately $559 million of short-term indebtedness as of June 30, 2005. CEI has obtained authorization from the PUCO to incur short-term debt of up to $500 million (including the utility money pool described below). CEI had the capability to issue $1.3 billion of additional FMB on the basis of property additions and retired bonds under the terms of its mortgage indenture. The issuance of FMB by CEI is subject to a provision of its senior note indenture 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, this provision would permit CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $570 million as of June 30, 2005. CEI has no restrictions on the issuance of preferred stock.

On April 20, 2005, Beaver County Industrial Development Authority pollution control bonds aggregating $53.9 million were refunded by CEI. The new bonds were issued in a Dutch Auction interest rate mode, insured with municipal bond insurance and secured by FMB.

On May 1, 2005, CEI redeemed $1.7 million of 7.00% Series B and Series C Pollution Control Revenue Bonds. The bonds were redeemed at par, plus accrued interest to the date of redemption. On June 6, 2005, CEI redeemed all 40,000 outstanding shares of $7.35 Series C preferred stock at $101.00 per share, plus accrued interest to the date of redemption.

On July 1, 2005, Ohio Air Quality Development Authority, Ohio Water Development Authority and Beaver County Industrial Development Authority pollution control bonds aggregating $2.9 million, $40.9 million and $45.15 million, respectively, were refunded by CEI. The new bonds were issued in a Dutch Auction interest rate mode, insured with municipal bond insurance. CEI provided FMB collateral to the bond insurer.

CEI has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount, 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 second quarter of 2005 was 2.93%.

CEI’s access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy. The ratings outlook from the rating agencies on all such securities is positive.

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in its outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.

Cash Flows from Investing Activities

In the second quarter of 2005, net cash used for investing activities increased $46 million from the second quarter of 2004. The increase in funds used for investing activities primarily reflected increased property additions and an increase in loans to associated companies. The $43 million increase in net cash provided from investing activities for the first six months of 2005 as compared to the same period last year was primarily due to increases in loan payments received from associated companies, partially offset by increased property additions.

During the second half of 2005, capital requirements for property additions are expected to be about $68 million, including $4 million for nuclear fuel. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. CEI has no additional requirements for sinking fund requirements for preferred stock and debt during the remainder of 2005.

CEI’s capital spending for the period 2005-2007 is expected to be about $368 million (excluding nuclear fuel) of which approximately $118 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to be approximately $79 million, of which about $13 million applies to 2005. During the same periods, CEI’s nuclear fuel investments are expected to be reduced by approximately $91 million and $27 million, respectively, as the nuclear fuel is consumed.

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, 2005, the present value of these operating lease commitments, net of trust investments, total $101 million.

CEI sells substantially all of its retail customer receivables to CFC, its wholly owned subsidiary. As of June 16, 2005, the CFC receivables financing structure was renewed and restructured from an off-balance sheet transaction to an on-balance sheet transaction. Under the new structure, any borrowings under the facility appear on the balance sheet as short-term debt.

Equity Price Risk

Included in CEI’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $254 million and $242 million as of June 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $25 million reduction in fair value as of June 30, 2005.

Outlook

The electric industry continues to transition to a more competitive environment and all of CEI's customers can select alternative energy suppliers. CEI continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. CEI has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties.

FirstEnergy Intra-System Generation Asset Transfers

On May 18, 2005, OE, CEI and TE, entered into the agreements described below (Agreements) implementing a series of intra-system generation asset transfers. When concluded, the asset transfers will result in the respective undivided ownership interests of the Ohio Companies in FirstEnergy’s nuclear, fossil and hydroelectric plants being owned by NGC, and FGCO, respectively. The generating plant interests that are being transferred do not include leasehold interests of CEI, TE and OE in plants that are currently subject to sale and leaseback arrangements with non-affiliates.

These transactions are being undertaken in connection with the Ohio Companies’ restructuring plans that were approved by the PUCO. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. FENOC, a subsidiary of FirstEnergy, currently operates and maintains the nuclear generation assets to be transferred. FGCO, as lessee under a master facility lease, leases the non-nuclear generation assets to be transferred and operates and maintains those assets. The transactions will essentially complete the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO, respectively, without impacting the operation of the plants.

As contemplated by the Agreements, CEI intends to transfer its interests in the nuclear generation assets to NGC through a sale at net book value. FGCO intends to exercise a purchase option under the Master Lease to acquire CEI’s non-nuclear generation assets at the values approved in the Ohio Transition Case.

Regulatory Matters

In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of CEI's customers elects to obtain power from an alternative supplier, CEI reduces the customer's bill with a "generation shopping credit," based on the generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. CEI has continuing PLR responsibility to its franchise customers through December 31, 2008 unless the PUCO accepts future competitive bid results prior to the end of that period under the revised Rate Stabilization Plan. As part of CEI's transition plan, it is obligated to supply electricity to customers who do not choose an alternative supplier. CEI is also required to provide 400 MW of low cost supply (MSG) to unaffiliated alternative suppliers who serve customers within its service area. FES acts as an alternate supplier for a portion of the load in CEI's franchise area.

CEI's Rate Stabilization Plan extends current generation prices through 2008, ensuring adequate generation supply at stabilized prices, and continues CEI's support of energy efficiency and economic development efforts. On October 1 and October 4, 2004, the OCC and NOAC, respectively, filed appeals with the Supreme Court of Ohio to overturn the June 9, 2004 PUCO order and associated entries on rehearing. Other key components of the Rate Stabilization Plan include the following:

Amortization period for transition costs being recovered through the RTC for CEI extends to as late as mid-2009;

Deferral of interest costs on the accumulated customer shopping incentives as new regulatory assets; and

Ability to request increases in generation charges during 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes.

On May 27, 2005, CEI filed an application with the PUCO to establish a generation rate adjustment rider under the Rate Stabilization Plan. The application seeks to implement recovery of increased fuel costs from 2006 through 2008 applicable to CEI’s retail customers through a tariff rider to be implemented January 1, 2006. The application reflects projected increases in fuel costs in 2006 compared to 2002 baseline costs. The new rider is seeking to recover all costs above the baseline. Various parties including the OCC have intervened in this case. The Ohio Companies have received discovery requests from the OCC and the PUCO staff. A procedural schedule has been established by the PUCO, with a hearing scheduled for October 4, 2005.

On December 9, 2004, the PUCO rejected the auction price results from a required competitive bid process and issued an entry stating that the pricing under the approved Rate Stabilization Plan will take effect on January 1, 2006. The PUCO may require CEI to undertake, no more often than annually, a similar competitive bid process to secure generation for the years 2007 and 2008. On July 22, 2005, FirstEnergy filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approved by the PUCO for CEI in 2004. Any acceptance of future competitive bid results would terminate the Rate Stabilization Plan pricing, but not the related approved accounting, and not until twelve months after the PUCO authorizes such termination.

On December 30, 2004, CEI filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application seeks recovery of these costs beginning January 1, 2006. At the time of filing the application, these costs were estimated to be approximately $16 million per year; however, CEI anticipates that this amount will increase. CEI requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted thereafter each July 1. CEI reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only other party in this proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This settlement, which was filed with the PUCO on July 22, 2005, provides for the rider recovery requested by CEI, with carrying charges applied in the subsequent year’s rider for any over or under collection while the then-current rider is in effect. If the settlement stipulation is approved by the PUCO, the actual amounts to be recovered through the January 1, 2006 rider will be submitted to the PUCO on or before November 1, 2005.

The second application seeks authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for CEI to defer incremental transmission and ancillary service-related charges incurred as a participant in the MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Deferral of all costs incurred prior to December 31, 2004 was denied. The PUCO also authorized CEI to accrue carrying charges on the deferred balances. An application filed with the PUCO to recover these deferred charges over a five-year period through the rider, beginning in 2006, is pending. The OCC, OPAE and CEI each filed applications for rehearing. CEI sought authority to defer the transmission and ancillary service related costs incurred during the period October 1, 2003 through December 29, 2004, while both OCC and OPAE sought to have the PUCO deny deferral of all costs. On July 6, 2005, the PUCO denied CEI's and OCC’s applications and, at the request of CEI, struck as untimely OPAE’s application. CEI and the OCC have sixty days from that date to file a notice of appeal with the Ohio Supreme Court.

On September 16, 2004, the FERC issued an order that imposed additional obligations on CEI under certain pre-Open Access transmission contracts among CEI and the cities of Cleveland and Painesville, Ohio. Under the FERC's original decision, CEI would have been responsible for a portion of new energy market charges imposed by MISO when its energy markets began in the spring of 2005. CEI filed for rehearing of the order from the FERC on October 18, 2004. On April 15, 2005, FERC issued an order on rehearing that "carves out" these contracts from the MISO Day 2 market, which became effective April 1, 2005. While the order on rehearing is favorable to CEI, the impact of the FERC decision on CEI is dependent upon many factors, including the arrangements made by the cities for transmission service and MISO's ability to administer the contracts. Accordingly, the impact of this decision cannot be determined at this time.

Regulatory assets are costs which have been authorized by the PUCO and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. CEI's regulatory assets as of June 30, 2005 and December 2004 were $0.9 billion and $1.0 billion, respectively. CEI is deferring customer shopping incentives and interest costs as new regulatory assets in accordance with its transition and rate stabilization plans. These regulatory assets total $354 million as of June 30, 2005 and will be recovered through a surcharge rate equal to the RTC rate in effect when the transition costs have been fully recovered. Recovery of the new regulatory assets will begin at that time and amortization of the regulatory assets for each accounting period will be equal to the surcharge revenue recognized during that period.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.

Environmental Matters

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

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including 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 nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR will require 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). CEI's Ohio and Pennsylvania fossil-fuel generation facilities will be subject to the caps on SO₂ and 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 CEI 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. On March 14, 2005, the EPA finalized a cap-and-trade program to reduce mercury emissions in two phases from coal-fired power plants. Initially, mercury emissions will decline 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. The future cost of compliance with these regulations may be substantial.

Climate Change

CEI cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO₂ emissions could require significant capital and other expenditures. However, the CO₂ emissions per KWH of electricity generated by CEI is lower than many regional competitors due to CEI's diversified generation sources which include low or non-CO₂ emitting gas-fired and nuclear generators.

Regulation of Hazardous Waste

CEI has been named a PRP 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, 2005, based on estimates of the total costs of cleanup, CEI's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. Included in Current Liabilities are accrued liabilities aggregating approximately $2.3 million as of June 30, 2005.

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

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

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 concludes, 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 website (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 also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability 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, and therefore FirstEnergy has not accrued a liability as of June 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station, in which CEI has a 51.38% interest. On December 10, 2004, FirstEnergy received a letter from the United States Attorney's Office stating that FENOC is a target of the federal grand jury investigation into alleged false statements made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. On February 10, 2005, FENOC received an additional subpoena for documents related to root cause reports regarding reactor head degradation and the assessment of reactor head management issues at Davis-Besse. On May 11, 2005, FENOC received a subpoena for documents related to outside meetings attended by Davis-Besse personnel on corrosion and cracking of control rod drive mechanisms and additional root cause evaluations.

On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head described above. On July 8, 2005, FENOC requested an additional 120 days to respond to the NOV. CEI has accrued the remaining liability for its share of the proposed fine of $1.8 million during the first quarter of 2005.

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and CEI, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

SFAS 154 - "Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3"

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in an income statement. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. FirstEnergy will adopt this Statement effective January 1, 2006.

FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the second period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective no later than the end of fiscal years ending after December 15, 2005. Therefore, FirstEnergy will adopt this Interpretation in the fourth quarter of 2005. FirstEnergy is currently evaluating the effect this Interpretation will have on its financial statements.

EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	*(In thousands)*
STATEMENTS OF INCOME

OPERATING REVENUES	$	259,109		$	243,366		$	500,864		$	478,764

OPERATING EXPENSES AND TAXES:
Fuel		14,404			13,073			26,973			23,287
Purchased power		72,300			74,687			152,456			157,095
Nuclear operating costs		46,689			36,166			105,852			78,858
Other operating costs		41,311			41,155			75,659			77,363
Provision for depreciation		15,209			14,380			29,889			28,433
Amortization of regulatory assets		33,231			27,362			68,096			61,028
Deferral of new regulatory assets		(12,670	)		(10,192	)		(22,094	)		(17,222	)
General taxes		13,620			12,028			27,801			26,328
Income taxes		27,817			8,080			23,849			6,502
Total operating expenses and taxes		251,911			216,739			488,481			441,672

OPERATING INCOME		7,198			26,627			12,383			37,092

OTHER INCOME (net of income taxes)		3,231			4,719			5,890			10,552

NET INTEREST CHARGES:
Interest on long-term debt		4,523			9,581			8,743			19,042
Allowance for borrowed funds used during construction		(188	)		(702	)		255			(2,102	)
Other interest expense		(1,582	)		889			1,234			1,595
Net interest charges		2,753			9,768			10,232			18,535

NET INCOME		7,676			21,578			8,041			29,109

PREFERRED STOCK DIVIDEND REQUIREMENTS		2,211			2,211			4,422			4,422

EARNINGS ON COMMON STOCK	$	5,465		$	19,367		$	3,619		$	24,687

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	7,676		$	21,578		$	8,041		$	29,109

OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized loss on available for sale securities		(501	)		(6,974	)		(2,184	)		(1,292	)
Income tax benefit related to other comprehensive income		96			2,861			791			530
Other comprehensive income (loss), net of tax		(405	)		(4,113	)		(1,393	)		(762	)

TOTAL COMPREHENSIVE INCOME	$	7,271		$	17,465		$	6,648		$	28,347

The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of
these statements.

THE TOLEDO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,		December 31,
	2005		2004
	*(In thousands)*
ASSETS
UTILITY PLANT:
In service	$	1,902,930	$	1,856,478
Less - Accumulated provision for depreciation		802,653		778,864
		1,100,277		1,077,614
Construction work in progress -
Electric plant		52,465		58,535
Nuclear fuel		4,063		15,998
		56,528		74,533
		1,156,805		1,152,147
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes		178,797		190,692
Nuclear plant decommissioning trusts		315,142		297,803
Long-term notes receivable from associated companies		40,014		39,975
Other		1,784		2,031
		535,737		530,501
CURRENT ASSETS:
Cash and cash equivalents		15		15
Receivables -
Customers (less accumulated provisions of $1,000 and $2,000, respectively,
for uncollectible accounts)		2,105		4,858
Associated companies		19,373		36,570
Other		3,182		3,842
Notes receivable from associated companies		16,099		135,683
Materials and supplies, at average cost		46,192		40,280
Prepayments and other		742		1,150
		87,708		222,398
DEFERRED CHARGES:
Goodwill		504,522		504,522
Regulatory assets		330,192		374,814
Property taxes		24,100		24,100
Other		39,189		25,424
		898,003		928,860
	$	2,678,253	$	2,833,906
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity -
Common stock, $5 par value, authorized 60,000,000 shares -
39,133,887 shares outstanding	$	195,670	$	195,670
Other paid-in capital		428,566		428,559
Accumulated other comprehensive income		18,646		20,039
Retained earnings		184,678		191,059
Total common stockholder's equity		827,560		835,327
Preferred stock		126,000		126,000
Long-term debt		296,482		300,299
		1,250,042		1,261,626
CURRENT LIABILITIES:
Currently payable long-term debt		90,950		90,950
Accounts payable -
Associated companies		34,806		110,047
Other		3,117		2,247
Notes payable to associated companies		333,136		429,517
Accrued taxes		57,466		46,957
Lease market valuation liability		24,600		24,600
Other		25,802		53,055
		569,877		757,373
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		235,448		221,950
Accumulated deferred investment tax credits		24,024		25,102
Retirement benefits		41,464		39,227
Asset retirement obligation		200,867		194,315
Lease market valuation liability		255,700		268,000
Other		100,831		66,313
		858,334		814,907
COMMITMENTS AND CONTINGENCIES (Note 13)
	$	2,678,253	$	2,833,906

The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part
of these balance sheets.

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	*(In thousands)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	7,676		$	21,578		$	8,041		$	29,109
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation		15,209			14,380			29,889			28,433
Amortization of regulatory assets		33,231			27,362			68,096			61,028
Deferral of new regulatory assets		(12,670	)		(10,192	)		(22,094	)		(17,222	)
Nuclear fuel and capital lease amortization		3,266			5,032			8,134			10,538
Amortization of electric service obligation		(1,391	)		-			(1,391	)		-
Deferred rents and lease market valuation liability		(29,242	)		(28,582	)		(44,466	)		(36,274	)
Deferred income taxes and investment tax credits, net		9,580			(2,651	)		8,193			(4,682	)
Accrued retirement benefit obligations		1,626			1,124			2,237			3,409
Accrued compensation, net		528			1,694			(737	)		961
Decrease (increase) in operating assets -
Receivables		(28,936	)		5,440			12,539			25,475
Materials and supplies		577			(2,217	)		(5,912	)		(3,651	)
Prepayments and other current assets		464			1,910			408			5,294
Increase (decrease) in operating liabilities -
Accounts payable		(81,306	)		(9,696	)		(74,371	)		(15,770	)
Accrued taxes		25,771			17,820			10,509			3,735
Accrued interest		(1,049	)		1,910			(196	)		(371	)
Prepayment for electric service -- education programs		37,954			-			37,954			-
Other		(6,618	)		8,488			(8,607	)		341
Net cash provided from (used for) operating activities		(25,330	)		53,400			28,226			90,353

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing -
Long-term debt		45,000			-			45,000			73,000
Redemptions and Repayments -
Long-term debt		(46,933	)		-			(46,933	)		(15,000	)
Short-term borrowings, net		(61,388	)		(23,761	)		(96,381	)		(117,060	)
Dividend Payments -
Common stock		(10,000	)		-			(10,000	)		-
Preferred stock		(2,211	)		(2,211	)		(4,422	)		(4,422	)
Net cash used for financing activities		(75,532	)		(25,972	)		(112,736	)		(63,482	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(14,249	)		(10,987	)		(32,168	)		(19,427	)
Loan repayments from (loans to) associated companies, net		121,155			(3,263	)		119,545			(657	)
Investments in lessor notes		(33	)		-			11,895			10,280
Contributions to nuclear decommissioning trusts		(7,136	)		(7,136	)		(14,271	)		(14,271	)
Other		1,125			(6,043	)		(491	)		(5,018	)
Net cash provided from (used for) investing activities		100,862			(27,429	)		84,510			(29,093	)

Net decrease in cash and cash equivalents		-			(1	)		-			(2,222	)
Cash and cash equivalents at beginning of period		15			16			15			2,237
Cash and cash equivalents at end of period	$	15		$	15		$	15		$	15

The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of
these statements.

Report of Independent Registered Public Accounting Firm

To the Stockholders 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, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

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, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(G) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 6 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

July 29, 2005

THE TOLEDO EDISON COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

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 provides power directly to some alternative energy suppliers under TE’s transition plan. TE has unbundled the price of electricity into its component elements - including generation, transmission, distribution and transition charges. TE’s power supply requirements are provided by FES - an affiliated company.

Results of Operations

Earnings on common stock in the second quarter of 2005 decreased to $5 million from earnings of $19 million in the second quarter of 2004. Earnings on common stock in the first six months of 2005 decreased to $4 million from $25 million in the first six months of 2004. The decrease in earnings in both periods of 2005 resulted principally from higher nuclear operating costs and a one-time income tax charge, partially offset by higher operating revenues and lower financing costs compared to the same period of 2004.

Operating revenues increased by $16 million, or 6.5%, in the second quarter of 2005 compared to the second quarter of 2004. Higher revenues in the second quarter of 2005 resulted from increased retail generation sales revenues of $11 million, distribution revenues of $4 million and wholesales sales (primarily to FES) of $2 million, partially offset by an increase in shopping incentive credits of $1 million. Retail generation sales revenues increased as a result of increased KWH sales (residential - $1 million, commercial - $2 million, industrial - $8 million). Higher residential and commercial revenues reflected increased KWH sales (24.5% and 23.2%, respectively), partially offset by lower unit prices. Residential and commercial sales volumes increased primarily due to warmer weather in TE’s service area. The commercial generation sales volume increase also reflects a reduction by 4.7 percentage points in customer shopping compared with the second quarter of 2004. Industrial revenues increased as a result of higher unit prices, partially offset by a 3.9% decrease in KWH sales.

Revenues from distribution throughput increased by $4 million in the second quarter of 2005 from the corresponding quarter of 2004. The increase was due to higher residential and commercial revenues ($9 million and $4 million, respectively) partially offset by a decrease in industrial revenues ($9 million). The impact of higher residential and commercial KWH sales contributed to the increase and offset the lower industrial sales volume and unit prices.

Operating revenues increased by $22 million, or 4.6% in the first six months of 2005 compared to the same period of 2004. Higher revenues in the first six months of 2005 resulted primarily from increased retail generation sales revenues of $21 million and wholesales sales (primarily to FES) of $5 million, partially offset by a decrease in distribution revenues of $2 million. Retail generation sales revenues increased as result of higher KWH sales in all customer sectors (residential - $1 million, commercial - $3 million, industrial - $17 million). Increases in residential and commercial revenues reflected increased KWH sales (6.3% and 13.9%, respectively) due to warmer weather, partially offset by lower unit prices. The higher industrial revenues resulted primarily from higher unit prices.

Revenues from distribution throughput decreased by $2 million in the first six months of 2005 compared to the same period in 2004 as a result of lower industrial KWH sales and reduced unit prices, which offset increases in KWH sales to residential and commercial customers.

Under the Ohio transition plan, TE provides incentives to customers to encourage switching to alternative energy providers. TE’s revenues were reduced by $1 million from additional credits in the second quarter and $2 million in the first six months of 2005 compared with the same periods of 2004. These revenue reductions are deferred for future recovery under TE’s transition plan and do not affect current period earnings (see Regulatory Matters below).

Changes in electric generation sales and distribution deliveries in the second quarter and first six months of 2005 from the corresponding periods of 2004, are summarized in the following table:

	Three			Six
Changes in KWH Sales	Months			Months
Increase (Decrease)
Electric Generation:
Retail		4.6	%		2.8	%
Wholesale		(6.5	)%		3.4	%
Total Electric Generation Sales		(1.8	)%		3.1	%

Distribution Deliveries:
Residential		25.5	%		9.3	%
Commercial		12.1	%		8.0	%
Industrial		(3.1	)%		(0.6	)%
Total Distribution Deliveries		6.4	%		3.9	%

Operating Expenses and Taxes

Total operating expenses and taxes increased by $35 million in the second quarter and $47 million in the first six months of 2005 from the same periods in 2004. The following table presents changes from the prior year by expense category.

	Three			Six
Operating Expenses and Taxes - Changes	Months			Months
Increase (Decrease)	*(In millions)*
Fuel costs	$	1		$	4
Purchased power costs		(2	)		(5	)
Nuclear operating costs		10			27
Other operating costs		-			(2	)
Provision for depreciation		1			1
Amortization of regulatory assets		6			7
Deferral of new regulatory assets		(3	)		(5	)
General taxes		2			2
Income taxes		20			18
Net increase in operating expenses and taxes	$	35		$	47

Higher fuel costs in the second quarter and first six months of 2005, compared with the same periods of 2004, resulted principally from increased fossil generation — up 12.4% and 19.8%, respectively. Lower purchased power costs in both periods reflect lower unit costs and a reduction in KWH purchased in the second quarter of 2005. Nuclear operating costs increased in both periods due to a scheduled refueling outage (including an unplanned extension) at the Perry Plant, a mid-cycle inspection outage at the Davis-Besse Plant during the first quarter of 2005, and the Beaver Valley Unit 2 refueling outage in the second quarter of 2005. Other operating costs remained unchanged in the second quarter of 2005 compared to the same period of 2004. MISO Day 2 expenses that began in the second quarter of 2005 were offset by decreased vegetation management expenses. Other operating costs decreased in the first six months of 2005 compared to the same period of 2004 in part from lower employee benefits costs.

Depreciation charges increased by $1 million in the second quarter and first six months of 2005 compared to the same periods of 2004 due to an increase in depreciable assets. This increase was partially offset by the effect of revised service life assumptions for fossil generating plants (See Note 3). Regulatory asset amortization increased in both periods due to the increased amortization of transition costs being recovered under the Rate Stabilization Plan. Deferrals of new regulatory assets increased in the second quarter and first six months of 2005 compared to the same periods of 2004, primarily due to higher shopping incentives and related interest ($1 million and $3 million, respectively) and the deferral of the PUCO-approved MISO administrative expenses and related interest ($1 million) that began in the second quarter of 2005.

On June 30, 2005, the State of Ohio enacted new tax legislation that creates a new Commercial Activity Tax (CAT), which is based on qualifying "taxable gross receipts" and will not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax is effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and personal property tax is phased-out over a four-year period at a rate of approximately 25%, annually beginning with the year ended 2005. For example, during the phase-out period the Ohio income-based franchise tax will be computed consistently with the prior tax law, except that the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period. As a result of the new tax structure, all net deferred tax benefits that are not expected to reverse during the five-year phase-in period were written-off as of June 30, 2005. The impact on income taxes associated with the required adjustment to net deferred taxes for the second quarter of 2005 was additional tax expense of approximately $18 million, which was partially offset by the phase-out of the Ohio income tax which reduced income taxes by approximately $1 million in the second quarter of 2005. See Note 12 to the consolidated financial statements.

Other Income

Other income decreased by $2 million in the second quarter of 2005 and $5 million in the first six months of 2005 from the same periods of 2004, primarily due to a decrease in earnings on nuclear decommissioning trust investments and the absence of interest income earned on associated company notes receivable that were repaid in May 2005. Additionally, the recognition of a $1.6 million proposed NRC fine related to the Davis-Besse Plant (see Outlook - Other Legal Proceedings) during the first quarter of 2005, caused other income to decrease during the first six months of 2005.

Net Interest Charges

Net interest charges continued to trend lower, decreasing by $7 million in the second quarter of 2005 and $8 million in the first six months of 2005 from the same periods of 2004, reflecting redemptions and refinancings subsequent to the end of the second quarter of 2004.

Capital Resources and Liquidity

TE’s cash requirements in 2005 for operating expenses, construction expenditures and scheduled debt maturities are expected to be met without increasing its net debt and preferred stock outstanding. Thereafter, TE expects to meet its contractual obligations with a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

As of June 30, 2005, TE's cash and cash equivalents of $15,000 remained unchanged from its December 31, 2004 balance.

Cash Flows From Operating Activities

Cash provided from operating activities during the second quarter and first six months of 2005, compared with the corresponding period of 2004 were as follows:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
Operating Cash Flows	2005			2004		2005			2004
	*(In millions)*

Cash earnings^*	$	28		$	30	$	56		$	75
Working capital and other		(53	)		23		(28	)		15
Total cash flows form operating activities	$	(25	)	$	53	$	28		$	90

^*Cash earnings are a non-GAAP measure (see reconciliation below).

Cash earnings, as disclosed in the table above, are not a measure of performance calculated in accordance with GAAP. TE believes that cash earnings is a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Reconciliation of Cash Earnings	2005			2004			2005			2004
	*(In millions)*

Net income (GAAP)	$	8		$	22		$	8		$	29
Non-cash charges (credits):
Provision for depreciation		15			14			30			29
Amortization of regulatory assets		33			27			68			61
Deferral of new regulatory assets		(13	)		(10	)		(22	)		(17	)
Nuclear fuel and capital lease amortization		3			5			8			10
Amortization of electric service obligation		(1	)		-			(1	)		-
Deferred rents and above-market lease liability		(29	)		(28	)		(44	)		(36	)
Deferred income taxes and investment tax credits, net		10			(3	)		8			(5	)
Accrued retirement benefits obligations		2			1			2			3
Accrued compensation, net		-			2			(1	)		1
Cash earnings (Non-GAAP)	$	28		$	30		$	56		$	75

Net cash provided from operating activities decreased by $78 million in the second quarter of 2005 from the second quarter of 2004 as a result of a $76 million decrease in working capital and $2 million decrease in cash earnings described above and under "Results of Operations". Net cash provided from operating activities decreased by $62 million in the first six months of 2005 compared to the same period last year as a result of a $43 million decrease in working capital and a $19 million decrease in cash earnings described above and under "Results of Operations". The change in working capital for both periods was primarily due to changes in accounts payable and accounts receivable, partially offset by funds received for prepaid electric service under the Ohio Schools Council’s Energy for Education Program that began in the second quarter of 2005.

Cash Flows From Financing Activities

Net cash used for financing activities increased by $50 million in the second quarter and first six months of 2005, as compared to the same periods of 2004, and resulted from an increase in net debt redemptions in both periods. The increase was also due to a $10 million increase in common stock dividends to FirstEnergy during the second quarter of 2005.

TE had $16 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $333 million of short-term indebtedness as of June 30, 2005. TE has authorization from the PUCO to incur short-term debt of up to $500 million (including the utility money pool described below). As of June 30, 2005, TE had the capability to issue $890 million of additional FMB on the basis of property additions and retired bonds under the terms of its mortgage indenture. Based upon applicable earnings coverage tests, TE could issue up to $950 million of preferred stock (assuming no additional debt was issued as of June 30, 2005).

TE has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal, 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 second quarter of 2005 was 2.93%.

On April 20, 2005, Beaver County Industrial Development Authority pollution control bonds aggregating $45 million were refunded by TE. The new bonds were issued in a Dutch Auction interest rate mode, insured with municipal bond insurance and secured by FMB.

On July 1, 2005, TE redeemed all of its 1.2 million outstanding shares of 7.00% Series A preferred stock at $25.00 per share, plus accrued dividends to the date of redemption.

TE’s access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy. On May 16, 2005, S&P affirmed its 'BBB-' corporate credit ratings on FirstEnergy and its units and revised its outlook on the companies to positive from stable. S&P stated that the rating affirmation and outlook revision reflects the successful restart of the three nuclear units from their respective outages that occurred during the first half of 2005. S&P noted that a subsequent rating upgrade could follow if FirstEnergy's financial performance continues to improve as projected and its nuclear operations further stabilize.

Cash Flows From Investing Activities

Net cash provided from investing activities increased by $128 million in the second quarter and $114 million in the first six months of 2005, from the same periods of 2004. These increases were primarily due to higher loan repayments from associated companies during the second quarter of 2005, partially offset by increased property additions.

TE’s capital spending for the last two quarters of 2005 is expected to be about $36 million (excluding $3 million for nuclear fuel). These cash requirements are expected to be satisfied from internal cash and short-term borrowings.

TE’s capital spending for the period 2005-2007 is expected to be about $192 million (excluding nuclear fuel), of which approximately $56 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to total approximately $56 million, of which about $10 million applies to 2005. During the same periods, TE’s nuclear fuel investments are expected to be reduced by approximately $64 million and $20 million, respectively, as the nuclear fuel is consumed.

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, 2005, the present value of these operating lease commitments, net of trust investments, totaled $531 million.

TE sells substantially all of its retail customer receivables to CFC, a wholly owned subsidiary of CEI. As of June 16, 2005, the CFC receivables financing structure was renewed and restructured from an off-balance sheet transaction to an on-balance sheet transaction. Under the new structure, any borrowings under the facility appear on the balance sheet as short-term debt.

Equity Price Risk

Included in TE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $199 million and $188 million as of June 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $20 million reduction in fair value as of June 30, 2005. Changes in the fair value of these investments are recorded in OCI unless recognized as a result of sales.

Outlook

The electric industry continues to transition to a more competitive environment and all of TE's customers can select alternative energy suppliers. TE continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. TE has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties.

FirstEnergy Intra-System Generation Asset Transfers

These transactions are being undertaken in connection with the Ohio Companies’ restructuring plans that were approved by the PUCO under applicable Ohio electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. FENOC, a subsidiary of FirstEnergy, currently operates and maintains the nuclear generation assets to be transferred. FGCO, as lessee under a master facility lease, leases the non-nuclear generation assets to be transferred and operates and maintains those assets. The transactions will essentially complete the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO, respectively, without impacting the operation of the plants.

As contemplated by the Agreements, TE intends to transfer its interests in the nuclear generation assets to NGC through a sale at net book value. FGCO intends to exercise a purchase option under the Master Lease to acquire TE’s non-nuclear generation assets at the values approved in the Ohio Transition case.

Regulatory Matters

As part of TE's transition plan, it is obligated to supply electricity to customers who do not choose an alternative supplier. TE is also required to provide 160 MW of low cost supply (MSG) to unaffiliated alternative suppliers who serve customers within its service area. FES acts as an alternate supplier for a portion of the load in TE's franchise area.

TE's Rate Stabilization Plan extends current generation prices through 2008, ensuring adequate generation supply at stabilized prices, and continues TE's support of energy efficiency and economic development efforts. On October 1 and October 4, 2004, the OCC and NOAC, respectively, filed appeals with the Supreme Court of Ohio to overturn the June 9, 2004 PUCO order and associated entries on rehearing. Other key components of the revised Rate Stabilization Plan include the following:

Amortization period for transition costs being recovered through the RTC extends to as late as mid-2008;

Deferral of interest costs on the accumulated customer shopping incentives as new regulatory assets; and

Ability to request increases in generation charges during 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes.

On May 27, 2005, TE filed an application with the PUCO to establish a generation rate adjustment rider under its Rate Stabilization Plan. The application seeks to implement recovery of increased fuel costs from 2006 through 2008 applicable to TE’s retail customers through a tariff rider to be implemented January 1, 2006. The application reflects projected increases in fuel costs in 2006 compared to 2002 baseline costs. The new rider is seeking to recover all costs above the baseline. Various parties including the OCC have intervened in this case. TE has received discovery requests from the OCC and the PUCO staff. A procedural schedule has been established by the PUCO, with a hearing scheduled for October 4, 2005.

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On December 30, 2004, TE filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application seeks recovery of these costs beginning January 1, 2006. At the time of filing the application, these costs were estimated to be approximately $0.1 million per year; however, TE anticipates that this amount will increase. TE requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted thereafter each July 1. TE reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only other party in this proceeding, Dominion Retail, Inc. agreed not to oppose the settlement. This settlement, which was filed with the PUCO on July 22, 2005, provides for the rider recovery requested by TE, with carrying charges applied in the subsequent year’s rider for any over or under collection while the then-current rider is in effect. If the settlement stipulation is approved by the PUCO, the actual amounts to be recovered through the January 1, 2006 rider will be submitted to the PUCO on or before November 1, 2005.

The second application seeks authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for TE to defer incremental transmission and ancillary service-related charges incurred as a participant in the MISO, but only for those costs incurred during the period December 30, 2004, through December 31, 2005. Deferral of all costs incurred prior to December 31, 2004 was denied. The PUCO also authorized TE to accrue carrying charges on the deferred balances. An application filed with the PUCO to recover these deferred charges over a five-year period through the rider, beginning in 2006, is pending. The OCC, OPAE and TE each filed applications for rehearing. TE sought authority to defer the transmission and ancillary service related costs incurred during the period October 1, 2003 through December 29, 2004, while both OCC and OPAE sought to have the PUCO deny deferral of all costs. On July 6, 2005, the PUCO denied TE's and OCC’s applications and, at the request of TE, struck as untimely OPAE’s application. TE and the OCC have sixty days from that date to file a notice of appeal with the Ohio Supreme Court.

TE records as regulatory assets costs which have been authorized by the PUCO and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. TE's regulatory assets as of June 30, 2005 and December 31, 2004, were $330 million and $375 million, respectively. TE is deferring customer shopping incentives and interest costs as new regulatory assets in accordance with its transition and rate stabilization plans. These regulatory assets total $108 million as of June 30, 2005 and will be recovered through a surcharge rate equal to the RTC rate in effect when the transition costs have been fully recovered. Recovery of the new regulatory assets will begin at that time and amortization of the regulatory assets for each accounting period will be equal to the surcharge revenue recognized during that period.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.

Environmental Matters

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

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including 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 nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR will require 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). TE's Ohio and Pennsylvania fossil-fuel generation facilities will be subject to the caps on SO₂ and 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 TE 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. On March 14, 2005, the EPA finalized a cap-and-trade program to reduce mercury emissions in two phases from coal-fired power plants. Initially, mercury emissions will decline 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. The future cost of compliance with these regulations may be substantial.

Climate Change

TE cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO₂ emissions could require significant capital and other expenditures. However, the CO₂ emissions per KWH of electricity generated by TE is lower than many regional competitors due to TE's diversified generation sources which include low or non-CO₂ emitting gas-fired and nuclear generators.

Regulation of Hazardous Waste

TE has been named a PRP 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, 2005, based on estimates of the total costs of cleanup, TE's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. Included in Current Liabilities are accrued liabilities aggregating approximately $0.2 million as of June 30, 2005. TE accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably determine the amount of such costs. Unasserted claims are reflected in TE's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to TE's normal business operations pending against TE and its subsidiaries. The most significant are described below.

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 concludes, 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 website (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 also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability 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, and therefore FirstEnergy has not accrued a liability as of June 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

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FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station, in which TE has a 48.62% interest. On December 10, 2004, FirstEnergy received a letter from the United States Attorney's Office stating that FENOC is a target of the federal grand jury investigation into alleged false statements made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. On February 10, 2005, FENOC received an additional subpoena for documents related to root cause reports regarding reactor head degradation and the assessment of reactor head management issues at Davis-Besse. On May 11, 2005, FENOC received a subpoena for documents related to outside meetings attended by Davis-Besse personnel on corrosion and cracking of control rod drive mechanisms and additional root cause evaluations.

On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head described above. On July 8, 2005, FENOC requested an additional 120 days to respond to the NOV. TE has accrued the remaining liability for its share of the proposed fine of $1.6 million during the first quarter of 2005.

If it were ultimately determined that FirstEnergy or its subsidiaries has legal liability based on events surrounding Davis-Besse, it could have a material adverse effect on FirstEnergy's or any of its subsidiaries' financial condition and results of operations.

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. FENOC operates the Perry Nuclear Power Plant, in which TE has a 19.91% interest (however, See Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which will include owned portions of the plant). On April 4, 2005, the NRC held a public forum 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 Plant operated "in a manner that preserved public health and safety" and met all cornerstone objectives although it remained under the heightened NRC oversight since August 2004. During the public forum and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process from increased oversight to possible impact to the plant’s operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition.

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On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and TE, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

SFAS 154 - "Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3"

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in an income statement. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. TE will adopt this Statement effective January 1, 2006.

FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective no later than the end of fiscal years ending after December 15, 2005. Therefore, TE will adopt this Interpretation in the fourth quarter of 2005. TE is currently evaluating the effect this Interpretation will have on its financial statements.

EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In March 2004, the EITF reached a consensus on the application guidance for Issue 03-1. EITF 03-1 provides a model for determining when investments in certain debt and equity securities are considered other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair value and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective for periods beginning after June 15, 2004, were delayed indefinitely by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, TE continues to evaluate its investments as required by existing authoritative guidance.

104

PENNSYLVANIA POWER COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	*(In thousands)*
STATEMENTS OF INCOME

OPERATING REVENUES	$	134,282		$	134,615		$	268,766		$	277,238

OPERATING EXPENSES AND TAXES:
Fuel		5,526			5,855			11,146			12,061
Purchased power		42,726			44,095			89,706			92,603
Nuclear operating costs		19,765			17,180			39,713			35,803
Other operating costs		16,743			15,474			29,511			29,159
Provision for depreciation		3,810			3,472			7,504			6,834
Amortization of regulatory assets		9,833			10,027			19,715			20,103
General taxes		6,444			4,488			12,916			11,122
Income taxes		13,232			14,846			25,653			29,884
Total operating expenses and taxes		118,079			115,437			235,864			237,569

OPERATING INCOME		16,203			19,178			32,902			39,669

OTHER INCOME (net of income taxes)		819			560			74			1,542

NET INTEREST CHARGES:
Interest expense		2,787			2,798			5,106			5,523
Allowance for borrowed funds used during construction		(1,476	)		(1,004	)		(2,843	)		(1,926	)
Net interest charges		1,311			1,794			2,263			3,597

NET INCOME		15,711			17,944			30,713			37,614

PREFERRED STOCK DIVIDEND REQUIREMENTS		738			640			1,378			1,280

EARNINGS ON COMMON STOCK	$	14,973		$	17,304		$	29,335		$	36,334

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	15,711		$	17,944		$	30,713		$	37,614

OTHER COMPREHENSIVE INCOME		-			-			-			-

TOTAL COMPREHENSIVE INCOME	$	15,711		$	17,944		$	30,713		$	37,614

The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of
these statements.

105

PENNSYLVANIA POWER COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,			December 31,
	2005			2004
	*(In thousands)*
ASSETS
UTILITY PLANT:
In service	$	892,826		$	866,303
Less - Accumulated provision for depreciation		371,569			356,020
		521,257			510,283
Construction work in progress -
Electric plant		122,232			104,366
Nuclear fuel		-			3,362
		122,232			107,728
		643,489			618,011
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		144,704			143,062
Long-term notes receivable from associated companies		32,795			32,985
Other		526			722
		178,025			176,769
CURRENT ASSETS:
Cash and cash equivalents		24			38
Notes receivable from associated companies		448			431
Receivables -
Customers (less accumulated provisions of $966,000 and $888,000,
respectively, for uncollectible accounts)		46,545			44,282
Associated companies		10,632			23,016
Other		939			1,656
Materials and supplies, at average cost		38,729			37,923
Prepayments and other		17,184			8,924
		114,501			116,270

DEFERRED CHARGES		9,915			10,106
	$	945,930		$	921,156
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity -
Common stock, $30 par value, authorized 6,500,000 shares -
6,290,000 shares outstanding	$	188,700		$	188,700
Other paid-in capital		65,035			64,690
Accumulated other comprehensive loss		(13,706	)		(13,706	)
Retained earnings		109,030			87,695
Total common stockholder's equity		349,059			327,379
Preferred stock		14,105			39,105
Long-term debt and other long-term obligations		121,167			133,887
		484,331			500,371
CURRENT LIABILITIES:
Currently payable long-term debt		25,774			26,524
Short-term borrowings -
Associated companies		25,597			11,852
Other		20,000			-
Accounts payable -
Associated companies		25,282			46,368
Other		2,627			1,436
Accrued taxes		26,158			14,055
Accrued interest		1,988			1,872
Other		8,712			8,802
		136,138			110,909
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		84,400			93,418
Asset retirement obligation		142,872			138,284
Retirement benefits		50,697			49,834
Regulatory liabilities		36,888			18,454
Other		10,604			9,886
		325,461			309,876
COMMITMENTS AND CONTINGENCIES (Note 13)
	$	945,930		$	921,156

The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of
these balance sheets.

106

PENNSYLVANIA POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	*(In thousands)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	15,711		$	17,944		$	30,713		$	37,614
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation		3,810			3,472			7,504			6,834
Amortization of regulatory assets		9,833			10,027			19,715			20,103
Nuclear fuel and other amortization		4,138			4,431			8,278			8,996
Deferred income taxes and investment tax credits, net		(2,644	)		(545	)		(4,955	)		(2,351	)
Decrease (increase) in operating assets -
Receivables		(1,054	)		19,948			10,838			19,734
Materials and supplies		(1,024	)		(1,221	)		(806	)		(2,296	)
Prepayments and other current assets		5,221			5,192			(8,260	)		(8,141	)
Increase (decrease) in operating liabilities -
Accounts payable		(17,005	)		(22,368	)		(19,895	)		(18,628	)
Accrued taxes		683			(4,023	)		12,103			4,786
Accrued interest		374			527			116			(1,429	)
Other		(315	)		1,084			463			3,941
Net cash provided from operating activities		17,728			34,468			55,814			69,163

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing -
Short-term borrowings, net		34,953			-			33,745			22,203
Redemptions and Repayments -
Preferred stock		(37,750	)		-			(37,750	)		-
Long-term debt		(810	)		(487	)		(810	)		(42,789	)
Short-term borrowings, net		-			(6,881	)		-			-
Dividend Payments -
Common stock		-			(15,000	)		(8,000	)		(23,000	)
Preferred stock		(738	)		(640	)		(1,378	)		(1,280	)
Net cash used for financing activities		(4,345	)		(23,008	)		(14,193	)		(44,866	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(12,571	)		(17,412	)		(41,093	)		(31,410	)
Contributions to nuclear decommissioning trusts		(398	)		(398	)		(797	)		(797	)
Loan repayments from associated companies		192			6,127			173			6,011
Other		(620	)		221			82			1,897
Net cash used for investing activities		(13,397	)		(11,462	)		(41,635	)		(24,299	)

Net decrease in cash and cash equivalents		(14	)		(2	)		(14	)		(2	)
Cash and cash equivalents at beginning of period		38			40			38			40
Cash and cash equivalents at end of period	$	24		$	38		$	24		$	38

The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of
these statements.

107

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of Pennsylvania Power Company:

We have reviewed the accompanying consolidated balance sheet of Pennsylvania Power Company and its subsidiary as of June 30, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

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, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(G) to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

July 29, 2005

108

PENNSYLVANIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

Penn is a wholly owned, electric utility subsidiary of OE. Penn conducts business in western Pennsylvania, providing regulated electric distribution services. Penn also provides generation services to those customers electing to retain Penn as their power supplier. Penn provides power directly to wholesale customers under previously negotiated contracts. Penn has unbundled the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Its power supply requirements are provided by FES - an affiliated company.

Results of Operations

Earnings on common stock in the second quarter of 2005 decreased to $15 million from $17 million in the second quarter of 2004. The lower earnings resulted primarily from increased operating expenses and taxes. Earnings on common stock in the first six months of 2005 decreased to $29 million from $36 million in the same period of 2004. The lower earnings resulted from decreased operating revenues and other income, partially offset by lower operating expenses and taxes and lower net interest charges.

Operating revenues decreased by $0.3 million in the second quarter of 2005 compared with the second quarter of 2004. The lower revenues primarily resulted from a $9 million decrease in wholesale sales to FES due to less nuclear generation available for sale. Higher retail electric generation revenues of $5 million resulted from increased KWH sales to residential and commercial customers, primarily due to cooler weather in the second quarter of 2005 in Penn's service area. These increases were partially offset by a $0.2 million decrease in revenues from industrial customers, reflecting lower KWH sales volume (11.7%) due in part to a 30.4% decrease in sales to a steel customer.

A $3 million increase in distribution throughput revenues was primarily due to higher KWH deliveries to residential and commercial customers due to the changes in weather. This increase in revenue was partially offset by lower KWH sales and unit prices for industrial customers. The changes in unit prices are attributable to changes in Penn's CTC rate schedules in April 2005 as a result of the annual CTC reconciliation.

Operating revenues decreased by $8 million, or 3%, in the first six months of 2005 compared with the same period of 2004. The lower revenues primarily resulted from an $18 million decrease in wholesale sales to FES due to less nuclear generation available for sale. Retail generation electric revenues increased by $8 million in all customer sectors due to higher retail generation KWH sales and higher composite unit prices. Industrial revenues increased by $2 million due to higher unit prices ($4 million), partially offset by a $2 million decrease due to lower KWH sales, which reflect in part an 18.6% decrease in sales to a steel customer.

In the first six months of 2005, distribution throughput revenues increased by $0.2 million primarily due to higher KWH deliveries to residential and commercial customers, partially offset by lower unit prices for commercial and industrial customers. Colder weather contributed to the higher KWH deliveries, and the changes in unit prices are attributable to changes in Penn's CTC rate schedules in April 2005.

Changes in kilowatt-hour sales by customer class in the second quarter and first six months of 2005 from the corresponding periods of 2004 are summarized in the following table:

	Three			Six
Changes in KWH Sales	Months			Months
Increase (Decrease)
Electric Generation:
Retail		4.5	%		2.5	%
Wholesale		(7.4	)%		(7.6	)%
Total Electric Generation Sales		(2.8	)%		(3.6	)%

Distribution Deliveries:
Residential		22.6	%		8.2	%
Commercial		11.7	%		6.5	%
Industrial		(11.7	)%		(5.7	)%
Total Distribution Deliveries		4.5	%		2.5	%

109

Operating Expenses and Taxes

Total operating expenses and taxes increased by $3 million in the second quarter and decreased by $2 million in the first six months of 2005 from the same periods last year. The following table presents changes from the prior year by expense category.

	Three			Six
Operating Expenses and Taxes - Changes	Months			Months
	*(In millions)*
Increase (Decrease)
Fuel costs	$	-		$	(1	)
Purchased power costs		(1	)		(3	)
Nuclear operating costs		3			4
Other operating costs		1			-
General taxes		2			2
Income taxes		(2	)		(4	)
Net increase (decrease) in operating expenses and taxes	$	3		$	(2	)

Lower fuel costs in the first six months of 2005, compared with the same period of 2004, resulted from reduced nuclear generation. Lower purchased power costs in the second quarter and first half of 2005 reflected lower unit prices for power. Nuclear operating costs increased in both periods of 2005, compared to the corresponding periods of 2004, due to a Perry scheduled refueling outage (including an unplanned extension) in the first and second quarters of 2005, a Beaver Valley Unit 2 scheduled refueling outage in the second quarter of 2005, and the absence of nuclear refueling outages in the first half of last year. Other operating costs increased in the second quarter of 2005 primarily due to increased vegetation management expenses and MISO Day 2 expenses that began in the second quarter of 2005. General taxes increased in both periods of 2005 primarily because of higher property and gross receipts taxes.

Other Income

Other income (net of income taxes) increased slightly in the second quarter of 2005 and decreased by $1 million in the first six months of 2005, compared with the same periods in 2004. The decrease in the first half of 2005 was due to liabilities recognized in the first quarter of 2005 for a $0.7 million civil penalty and $0.8 million for probable future cash contributions toward environmentally beneficial projects related to the Sammis Plant settlement (see Outlook - Environmental Matters) and the absence of a $1 million gain from the sale of an investment in the first six months of 2004.

Net Interest Charges

Net interest charges continued to trend lower, decreasing by $0.5 million in the second quarter of 2005 and $1 million in the first six months of 2005 from the corresponding periods last year, reflecting redemptions of $35 million in total principal amount of debt securities since the second quarter of 2004.

Capital Resources and Liquidity

Penn’s cash requirements for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met with a combination of cash from operations and funds from the capital markets. Available borrowing capacity under credit facilities will be used to manage working capital requirements.

Changes in Cash Position

As of June 30, 2005, Penn had $24,000 of cash and cash equivalents, compared with $38,000 as of December 31, 2004. The major sources of changes in these balances are summarized below.

110

Cash Flows From Operating Activities

Net cash provided from operating activities in the second quarter and first six months of 2005, compared with the corresponding 2004 periods, was as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Operating Cash Flows	2005			2004			2005			2004
	*(In millions)*

Cash earnings ^(*)	$	32		$	36		$	62		$	74
Working capital and other		(14	)		(2	)		(6	)		(5	)
Total cash flows form operating activities	$	18		$	34		$	56		$	69

^(*) Cash earnings is a non-GAAP measure (see reconciliation below).

Cash earnings (in the table above) are not a measure of performance calculated in accordance with GAAP. Penn believes that cash earnings is a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.

	Three Months Ended					Six Months Ended
	June 30,					June 30,
Reconciliation of Cash Earnings	2005			2004		2005			2004
	*(In millions)*

Net income (GAAP)	$	16		$	18	$	31		$	38
Non-cash charges (credits):
Provision for depreciation		4			3		8			7
Amortization of regulatory assets		10			10		20			20
Nuclear fuel and other amortization		4			4		8			9
Deferred income taxes and investment tax credits, net		(3	)		-		(5	)		(2	)
Other non-cash items		1			1		-			2
Cash earnings (Non-GAAP)	$	32		$	36	$	62		$	74

The $4 million and $12 million decreases in cash earnings in the second quarter and six-month period, respectively, are described under "Results of Operations." The $12 million working capital change in the second quarter was primarily due to a $21 million change in receivables, partially offset by changes of $5 million in accounts payable and $5 million in accrued taxes. The $1 million working capital change in the six month period was primarily due to a $9 million change in receivables, almost entirely offset by changes of $1 million in accounts payable and $7 million in accrued taxes.

Cash Flows From Financing Activities

Net cash used for financing activities totaled $4 million in the second quarter of 2005, compared with $23 million in the same period last year. The $19 million decrease resulted primarily from an increase in net short-term borrowings, higher optional redemptions of preferred stock and reduced common stock dividends to OE in the second quarter of 2005, compared with the second quarter of 2004.

On May 16, 2005, Penn redeemed all 127,500 outstanding shares of 7.625% preferred stock at $102.29 per share and all 250,000 outstanding shares of 7.75% preferred stock at $100 per share, both plus accrued dividends to the date of redemption. The total par value of the preferred stock redeemed was $37.8 million.

Net cash used for financing activities totaled $14 million in the first six months of 2005, compared with $45 million in the same period last year. The $31 million decrease resulted primarily from increased short-term borrowings and optional redemptions of preferred stock, reduced debt redemptions and a decrease in common stock dividends to OE in the first six months of 2005, compared with the corresponding 2004 period.

Penn had $472,000 of cash and temporary investments (which included short-term notes receivable from associated companies) and $46 million of short-term indebtedness as of June 30, 2005. Penn has authorization from the SEC to incur short-term debt up to its charter limit of $49 million (including the utility money pool). Penn had the capability to issue $498 million of additional FMB on the basis of property additions and retired bonds as of June 30, 2005. Based upon applicable earnings coverage tests, Penn could issue up to $373 million of preferred stock (assuming no additional debt was issued) as of June 30, 2005.

111

Penn has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount of such a 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 under these arrangements in the second quarter of 2005 was 2.93%.

In addition, Penn Power Funding LLC (Penn Funding), a wholly owned subsidiary of Penn, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Penn. Penn Funding can borrow up to $25 million under a receivables financing arrangement. As a separate legal entity with separate creditors, Penn Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Penn. As of June 30, 2005, the facility was drawn for $20 million. On July 15, 2005, the facility was renewed until June 29, 2006. The annual facility fee is 0.25% on the entire finance limit.

Penn’s access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of OE and FirstEnergy. The ratings outlook on all securities is positive.

Cash Flows From Investing Activities

Net cash used in investing activities totaled $13 million in the second quarter of 2005, compared with $11 million in the second quarter of 2004. The $2 million increase reflects a decrease in loan repayments from associated companies, partially offset by a decrease in property additions. Net cash used in investing activities totaled $42 million in the first six months of 2005, compared with $24 million in the same period last year. The $18 million increase was primarily a result of increased property additions and reduced loan repayments from associated companies.

During the second half of 2005, capital requirements for property additions are expected to be about $54 million, including $10 million for nuclear fuel. Penn expects to contribute up to $65 million (unfunded liability recognized as of June 30, 2005) for nuclear decommissioning in connection with the generation asset transfers described below, and has additional requirements of $0.5 million to meet sinking fund requirements for long-term debt during the remainder of 2005. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements.

Penn’s capital spending for the period 2005-2007 is expected to be about $227 million (excluding nuclear fuel), of which approximately $81 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to be approximately $66 million, of which about $15 million relates to 2005. During the same periods, Penn’s nuclear fuel investments are expected to be reduced by approximately $53 million and $17 million, respectively, as the nuclear fuel is consumed. After completion of the asset transfers described further below, Penn’s future capital requirements are expected to be substantially reduced and the nuclear fuel obligations would be terminated. Penn had no other material obligations as of June 30, 2005 that have not been recognized on its Consolidated Balance Sheet.

On July 22, 2005, the Philadelphia Stock Exchange filed an application with the SEC for termination of the listing of the following three series of Penn’s cumulative preferred stock, $100 par value, as such series no longer met the Exchange’s technical listing requirements regarding the number of outstanding shares and the number of holders: 4.24% Series, 4.25% Series and 4.64% Series. The Exchange requested an effective date of August 12, 2005.

112

Equity Price Risk

Included in Penn’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $57 million as of both dates, June 30, 2005 and December 31, 2004. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $6 million reduction in fair value as of June 30, 2005.

FirstEnergy Intra-System Generation Asset Transfers

On May 13, 2005, Penn entered into an agreement to transfer its ownership interests in its nuclear and fossil generating facilities to NGC and FGCO, respectively. These transactions are being undertaken in connection with Penn’s restructuring plan that was approved by the PPUC under applicable Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plan, Penn’s generation assets were required to be separated from the regulated delivery business through transfers to a separate corporate entity. FENOC, a subsidiary of FirstEnergy, currently operates and maintains the nuclear generation assets to be transferred. FGCO, as lessee under a master facility lease, leases the non-nuclear generation assets to be transferred and operates and maintains those assets. The transactions will essentially complete the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO, respectively, without impacting the operation of the plants.

Penn intends to transfer its interests in the nuclear generation assets to NGC through a spin-off by way of a dividend. FGCO intends to exercise a purchase option under the Master Lease to acquire Penn’s fossil generation assets. Consummation of the transactions is subject to receipt of all necessary regulatory authorizations and other consents and approvals. Penn expects to complete the asset transfers in the second half of 2005.

Regulatory Matters

Regulatory assets and liabilities are costs which have been authorized by the PPUC and the FERC for recovery from or credit to customers in future periods and, without such authorization, would have been charged or credited to income when incurred. Penn's net regulatory liabilities were approximately $37 million and $18 million as of June 30, 2005 and December 31, 2004, respectively, and are included in Noncurrent Liabilities on the Consolidated Balance Sheets.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania, including a more detailed discussion of reliability initiatives.

Environmental Matters

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

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including 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 nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR will require additional reductions of NO_x and SO₂emissions in two phases (Phase I in 2009 for NO_x, 2010 for SO₂ and Phase II in 2015 for both NO_x and SO₂). Penn's Ohio and Pennsylvania fossil-fuel generation facilities will be subject to the caps on SO₂ and NO_xemissions. 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 Penn operates affected facilities.

113

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. On March 14, 2005, the EPA finalized a cap-and-trade program to reduce mercury emissions in two phases from coal-fired power plants. Initially, mercury emissions will decline 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. The future cost of compliance with these regulations may be substantial.

W. H. Sammis Plant

In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities covering 44 power plants, including the W. H. Sammis Plant, which is owned by OE and Penn. In addition, the U.S. Department of Justice (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 New Source Review cases. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. 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 W. H. Sammis Plant New Source Review litigation. This settlement agreement, which is in the form of a Consent Decree that was approved by the Court on July 11, 2005, requires OE and Penn to reduce emissions from the W. H. Sammis Plant and other plants through the installation of pollution control devices requiring capital expenditures currently estimated to be $1.1 billion (primarily in the 2008 to 2011 time period). The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy purchase power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million, of which Penn's share is $0.7 million. Results for the first quarter of 2005 included the $0.7 million penalty payable by Penn and an $0.8 million liability for probable future cash contributions toward environmentally beneficial projects.

Climate Change

Penn cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO₂ emissions could require significant capital and other expenditures. However, the CO₂ emissions per KWH of electricity generated by Penn is lower than many regional competitors due to Penn's diversified generation sources which include low or non-CO₂ emitting gas-fired and nuclear generators.

Other Legal Proceedings

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to Penn's normal business operations pending against Penn. The most significant not otherwise discussed above are described below.

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 concludes, 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 website (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 also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability 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, and therefore FirstEnergy has not accrued a liability as of June 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

114

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. FENOC operates the Perry Nuclear Power Plant, in which Penn has a 5.24% interest (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which will include owned portions of the plant). On April 4, 2005, the NRC held a public forum 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 Plant operated "in a manner that preserved public health and safety" and met all cornerstone objectives although it remained under the heightened NRC oversight since August 2004. During the public forum and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process from increased oversight to possible impact to the plant’s operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition.

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

SFAS 154 - "Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3"

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in an income statement. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Penn will adopt this Statement effective January 1, 2006.

115

FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective no later than the end of fiscal years ending after December 15, 2005. Therefore, Penn will adopt this Interpretation in the fourth quarter of 2005. Penn is currently evaluating the effect this Interpretation will have on its financial statements.

EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In March 2004, the EITF reached a consensus on the application guidance for Issue 03-1. EITF 03-1 provides a model for determining when investments in certain debt and equity securities are considered other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair value and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective for periods beginning after June 15, 2004, were delayed indefinitely by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, Penn continues to evaluate its investments as required by existing authoritative guidance.

116

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	*(In thousands)*
STATEMENTS OF INCOME

OPERATING REVENUES	$	595,291		$	549,665		$	1,124,383		$	1,047,789

OPERATING EXPENSES AND TAXES:
Purchased power		321,393			285,742			598,525			556,475
Other operating costs		80,239			80,844			181,306			167,660
Provision for depreciation		19,856			19,093			40,062			38,168
Amortization of regulatory assets		70,250			67,949			138,624			132,434
Deferral of new regulatory assets		(27,765	)		-			(27,765	)		-
General taxes		14,824			14,738			30,264			30,670
Income taxes		42,366			26,343			54,849			35,456
Total operating expenses and taxes		521,163			494,709			1,015,865			960,863

OPERATING INCOME		74,128			54,956			108,518			86,926

OTHER INCOME (net of income taxes)		273			1,104			317			2,607

NET INTEREST CHARGES:
Interest on long-term debt		19,276			19,803			38,681			40,531
Allowance for borrowed funds used during construction		(437	)		(151	)		(840	)		(271	)
Deferred interest		(916	)		(891	)		(1,827	)		(1,814	)
Other interest expense		1,155			463			2,979			853
Net interest charges		19,078			19,224			38,993			39,299

NET INCOME		55,323			36,836			69,842			50,234

PREFERRED STOCK DIVIDEND REQUIREMENTS		125			125			250			250

EARNINGS ON COMMON STOCK	$	55,198		$	36,711		$	69,592		$	49,984

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	55,323		$	36,836		$	69,842		$	50,234

OTHER COMPREHENSIVE INCOME:
Unrealized gain on derivative hedges		36			59			105			44
Unrealized loss on available for sale securities		-			-			-			(8	)
Other comprehensive income		36			59			105			36
Income tax related to other comprehensive income		(15	)		-			(43	)		4
Other comprehensive income, net of tax		21			59			62			40

TOTAL COMPREHENSIVE INCOME	$	55,344		$	36,895		$	69,904		$	50,274

The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an
integral part of these statements.

117

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,			December 31,
	2005			2004
	*(In thousands)*
ASSETS
UTILITY PLANT:
In service	$	3,803,593		$	3,730,767
Less - Accumulated provision for depreciation		1,409,221			1,380,775
		2,394,372			2,349,992
Construction work in progress		76,134			75,012
		2,470,506			2,425,004
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		139,831			138,205
Nuclear fuel disposal trust		163,074			159,696
Long-term notes receivable from associated companies		19,767			20,436
Other		16,459			19,379
		339,131			337,716
CURRENT ASSETS:
Cash and cash equivalents		412			162
Receivables -
Customers (less accumulated provisions of $3,101,000 and $3,881,000,
respectively, for uncollectible accounts)		273,361			201,415
Associated companies		4,387			86,531
Other (less accumulated provisions of $241,000 and $162,000,
respectively, for uncollectible accounts)		35,824			39,898
Materials and supplies, at average cost		2,258			2,435
Prepayments and other		98,014			31,489
		414,256			361,930
DEFERRED CHARGES:
Regulatory assets		2,137,692			2,176,520
Goodwill		1,983,699			1,985,036
Other		3,958			4,978
		4,125,349			4,166,534
	$	7,349,242		$	7,291,184
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity -
Common stock, $10 par value, authorized 16,000,000 shares -
15,371,270 shares outstanding	$	153,713		$	153,713
Other paid-in capital		3,014,583			3,013,912
Accumulated other comprehensive loss		(55,472	)		(55,534	)
Retained earnings		72,863			43,271
Total common stockholder's equity		3,185,687			3,155,362
Preferred stock		12,649			12,649
Long-term debt and other long-term obligations		1,022,320			1,238,984
		4,220,656			4,406,995
CURRENT LIABILITIES:
Currently payable long-term debt		166,868			16,866
Notes payable -
Associated companies		279,105			248,532
Accounts payable -
Associated companies		13,900			20,605
Other		163,524			124,733
Accrued taxes		59,844			2,626
Accrued interest		9,770			10,359
Other		57,661			65,130
		750,672			488,851
NONCURRENT LIABILITIES:
Power purchase contract loss liability		1,202,184			1,268,478
Accumulated deferred income taxes		691,505			645,741
Nuclear fuel disposal costs		172,207			169,884
Asset retirement obligation		74,869			72,655
Retirement benefits		99,755			103,036
Other		137,394			135,544
		2,377,914			2,395,338
COMMITMENTS AND CONTINGENCIES (Note 13)
	$	7,349,242		$	7,291,184

The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an
integral part of these balance sheets.

118

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	*(In thousands)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	55,323		$	36,836		$	69,842		$	50,234
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation		19,856			19,093			40,062			38,168
Amortization of regulatory assets		70,250			67,949			138,624			132,434
Deferral of new regulatory assets		(27,765	)		-			(27,765	)
Deferred purchased power and other costs		(52,906	)		(40,408	)		(126,265	)		(78,390	)
Deferred income taxes and investment tax credits, net		9,258			(19,977	)		16,426			(19,747	)
Accrued retirement benefit obligation		1,447			2,946			(3,281	)		(8,768	)
Accrued compensation, net		(10,161	)		39			(4,748	)		(816	)
NUG power contract restructuring		-			52,800			-			52,800
Decrease (increase) in operating assets -
Receivables		(577	)		6,405			14,271			7,843
Materials and supplies		95			(11	)		177			347
Prepayments and other current assets		(75,775	)		(64,080	)		(66,525	)		(39,704	)
Increase (decrease) in operating liabilities -
Accounts payable		62,477			16,294			32,087			945
Accrued taxes		18,341			14,288			57,218			63,768
Accrued interest		(15,308	)		(16,006	)		(589	)		(5,228	)
Other		4,731			(23,388	)		17,054			(19,064	)
Net cash provided from operating activities		59,286			52,780			156,588			174,822

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			300,000			-			300,000
Short-term borrowings, net		74,310			7,552			30,572			-
Redemptions and Repayments-
Long-term debt		(59,444	)		(293,477	)		(63,327	)		(297,068	)
Short-term borrowings, net		-			-			-			(72,192	)
Dividend Payments-
Common stock		(20,000	)		(15,000	)		(40,000	)		(20,000	)
Preferred stock		(125	)		(125	)		(250	)		(250	)
Net cash used for financing activities		(5,259	)		(1,050	)		(73,005	)		(89,510	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(54,537	)		(55,213	)		(82,661	)		(83,425	)
Loan repayments from (loans to) associated companies, net		1,568			645			670			(411	)
Other		(687	)		2,838			(1,342	)		(1,465	)
Net cash used for investing activities		(53,656	)		(51,730	)		(83,333	)		(85,301	)

Net increase in cash and cash equivalents		371			-			250			11
Cash and cash equivalents at beginning of period		41			282			162			271
Cash and cash equivalents at end of period	$	412		$	282		$	412		$	282

The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral
part of these statements.

119

Report of Independent Registered Public Accounting Firm

To the Stockholders 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, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

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, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 9 to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 6 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

July 29, 2005

120

JERSEY CENTRAL POWER & LIGHT COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

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. JCP&L has restructured its electric rates into unbundled service charges and transition cost recovery charges. JCP&L continues to deliver power to homes and businesses through its existing distribution system.

Results of Operations

Earnings on common stock in the second quarter of 2005 increased to $55 million from $37 million in 2004. For the first six months of 2005, earnings on common stock increased to $70 million compared to $50 million for the same period of 2004. The increase in earnings for both periods was primarily due to higher operating revenues and the deferral of a new regulatory asset, partially offset by increases in purchased power costs. Other operating costs were also higher in the first six months of 2005 compared to the same period in 2004.

Operating revenues increased $46 million or 8.3% in the second quarter and $77 million or 7.3% in the first six months of 2005 compared with the same periods in 2004. The higher revenues in both periods were primarily due to increased retail electric generation revenues ($33 million for the second quarter and $51 million for the first six months of 2005) and distribution revenues ($22 million for the second quarter and $34 million for the first six months of 2005), partially offset by a decline in wholesale revenues ($4 million for the second quarter and $8 million for the first six months of 2005).

Higher retail generation revenues in both the second quarter and first six months of 2005 as compared to the previous year resulted from increased KWH sales to residential and commercial customers. Revenue from residential customers increased in the second quarter and first six months of 2005 by $22 million and $36 million, respectively. Commercial generation revenue increased for the same periods by $12 million and $20 million, respectively. The increases were attributable to higher KWH sales (residential - 18.2% and commercial - 10.0% in the second quarter of 2005; residential - 15.5% and commercial - 9.6% for the first six months of 2005) primarily due to lower customer shopping. Generation provided by alternative suppliers to residential and commercial customers as a percent of total sales delivered in JCP&L’s service area decreased by 11.1% and 5.4%, respectively, in the second quarter of 2005 and 11.6% and 4.5%, respectively, in the first six months of 2005. Industrial sales decreased by $0.4 million in the second quarter and $6 million in the first six months of 2005 reflecting the effect of 3.4% and 20.3% declines in KWH sales, respectively.

JCP&L's BGS obligation has been transferred to external parties as a result of an NJBPU auction process that extended the termination of JCP&L's BGS obligation through May 2006 (see Outlook - Regulatory Matters). Higher unit prices resulted from the BGS auction. The increase in total retail generation KWH sales reduced energy available for sale in the wholesale market which resulted in lower wholesale sales revenues of $4 million in the second quarter of 2005 and $8 million in the first six months of 2005 as compared to the respective periods in 2004.

Distribution revenues increased by $22 million in the second quarter and $34 million in the first six months of 2005, as compared to the same periods of 2004, due to higher composite unit prices, caused in part by the June 1, 2005 rate increase, and increased KWH sales to the residential and commercial sectors. The increase in distribution revenues from the industrial sector was partially offset by decreases in KWH sales.

Operating revenues also reflected a $2 million payment received in the first six months of 2005 under a contract provision associated with the prior sale of TMI Unit 1. Under the contract, additional payments are received if subsequent energy prices rise above specified levels and are credited to JCP&L’s customers, resulting in no impact to current earnings.

121

Changes in kilowatt-hour sales by customer class in the second quarter and in the first six months of 2005 compared to the same periods of 2004 are summarized in the following table:

	Three			Six
Changes in KWH Sales	Months			Months
Increase (Decrease)
Electric Generation:
Retail		13.5	%		10.9	%
Wholesale		(15.0	)%		(15.2	)%
Total Electric Generation Sales		6.2	%		4.2	%

Distribution Deliveries:
Residential		5.1	%		2.2	%
Commercial		2.5	%		3.2	%
Industrial		(4.2	)%		(2.2	)%
Total Distribution Deliveries		2.7	%		2.0	%

Operating Expenses and Taxes

Total operating expenses and taxes increased $26 million and $55 million in the second quarter and in the first six months of 2005, respectively, as compared to the prior year. The following table presents changes from the prior year by expense category.

	Three			Six
Operating Expenses and Taxes - Changes	Months			Months
	*(In millions)*
Increase (Decrease)
Purchased power costs	$	36		$	42
Other operating costs		(1	)		14
Provision for depreciation		-			2
Amortization of regulatory assets		3			6
Deferral of new regulatory assets		(28	)		(28	)
Income taxes		16			19
Net increase in operating expenses and taxes	$	26		$	55

As the result of higher KWH purchases to supply the increased retail generation sales, purchased power costs increased by $36 million in the second quarter and $42 million in the first six months of 2005 as compared to the same periods in 2004. Other operating costs decreased $1 million in the second quarter of 2005, but increased $14 million in the first six months of 2005 compared to the same periods of 2004, reflecting in part the effects of a JCP&L labor strike. The JCP&L labor strike, which affected approximately 1,300 employees, began on December 8, 2004 and lasted until March 15, 2005.

Deferral of new regulatory assets decreased expenses by $28 million in both the second quarter and the first six months of 2005, reflecting NJBPU’s (see Regulatory Matters) approval to defer $28 million of previously incurred reliability expenses. Amortization of regulatory assets increased $3 million in the second quarter and $6 million in the first six months of 2005 due to an increase in the level of MTC revenue recovery.

Capital Resources and Liquidity

JCP&L’s cash requirements in 2005 for operating expenses, construction expenditures and scheduled debt maturities are expected to be met with a combination of cash from operations and funds from the capital markets. Thereafter, JCP&L expects to meet its contractual obligations with cash from operations.

Changes in Cash Position

As of June 30, 2005, JCP&L had $412,000 of cash and cash equivalents compared with $162,000 as of December 31, 2004. The major sources for changes in these balances are summarized below.

122

Cash Flows From Operating Activities

Cash provided from operating activities in the second quarter and in the first six months of 2005 compared with 2004, were as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Operating Cash Flows	2005			2004			2005		2004
	*(In millions)*

Cash earnings ^(*)	$	65		$	66		$	103	$	113
Working capital and other		(6	)		(13	)		54		62
Total cash flows from operating activities	$	59		$	53		$	157	$	175

^(*) Cash earnings is a non-GAAP measure (see reconciliation below).

Cash earnings (in the table above) are not a measure of performance calculated in accordance with GAAP. JCP&L believes that cash earnings is a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Reconciliation of Cash Earnings	2005			2004			2005			2004
	*(In millions)*

Net income (GAAP)	$	55		$	37		$	70		$	50
Non-cash charges (credits):
Provision for depreciation		20			19			40			38
Amortization of regulatory assets		71			68			139			132
Deferral of new regulatory assets		(28	)		-			(28	)		-
Deferred purchased power and other costs		(53	)		(40	)		(126	)		(78	)
Deferred income taxes		9			(20	)		16			(20	)
Other non-cash items		(9	)		2			(8	)		(9	)
Cash earnings (Non-GAAP)	$	65		$	66		$	103		$	113

The $1 million and $10 million decrease in cash earnings for the second quarter and the first six months of 2005 is described above and under "Results of Operations". The $7 million increase for the second quarter and the $8 million decrease for the first six months of 2005 from working capital primarily resulted from changes in receivables.

Cash Flows From Financing Activities

Net cash used for financing activities was $5 million in the second quarter of 2005 compared to $1 million in the second quarter of 2004. The increase resulted primarily from an increase in common stock dividends to FirstEnergy. Net cash used for financing activities was $73 million for the first six months of 2005 and $90 million for the same period of 2004. The $17 million reduction resulted from a $37 million decrease in net debt redemptions, partially offset by a $20 million increase in common stock dividends to FirstEnergy. JCP&L retired $63 million of First Mortgage Bonds, Medium Term Notes and Secured Transition Bonds in the first six months of 2005.

JCP&L had approximately $412,000 of cash and temporary investments and $279 million of short-term indebtedness as of June 30, 2005. JCP&L has authorization from the SEC to incur short-term debt up to its charter limit of $1.521 billion (including the utility money pool). JCP&L will not issue FMB other than as collateral for senior notes, since its senior note indentures prohibit (subject to certain exceptions) JCP&L from issuing any debt which is senior to the senior notes. As of June 30, 2005, JCP&L had the capability to issue $597 million of additional senior notes based upon FMB collateral. Based upon applicable earnings coverage tests and its charter, JCP&L could issue $866 million of preferred stock (assuming no additional debt was issued) as of June 30, 2005.

123

JCP&L has the ability to borrow from FirstEnergy and its regulated affiliates to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal, 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 was 2.93% in the second quarter of 2005 and 2.79% in the first six months of 2005.

JCP&L’s access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy. The ratings outlook from the rating agencies on all such securities is positive.

Cash Flows From Investing Activities

Net cash used for investing activities was $54 million in the second quarter and $83 million for the first six months of 2005 compared to $52 million and $85 million for the same periods of 2004. JCP&L’s capital spending for the period 2005-2007 is expected to be about $511 million for property additions, of which approximately $183 million applies to 2005. During the last two quarters of 2005, capital requirements for property additions and improvements are expected to be about $100 million.

Market Risk Information

JCP&L uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price fluctuations. Its Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughout JCP&L. The committee is responsible for promoting the effective design and implementation of sound risk management programs. The committee also oversees compliance with corporate risk management policies and established risk management practices.

Commodity Price Risk

JCP&L is exposed to market risk primarily due to fluctuations in electricity and natural gas prices. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including forward contracts, options and futures contracts. The derivatives are used for hedging purposes. Most of its non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. As of June 30, 2005, JCP&L had commodity derivative contracts with a fair value of $14 million. A decrease of $1 million in the value of this asset was recorded in the first six months of 2005 as a decrease in a regulatory liability, and therefore, had no impact on net income.

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, JCP&L relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. JCP&L uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for valuation of derivative contracts as of June 30, 2005 are summarized by year in the following table:

124

Sources of Information -
Fair Value by Contract Year	2005⁽¹⁾		2006		2007		2008		Thereafter		Total


External sources ⁽²⁾	$	3	$	2	$	2	$	-	$	-	$	7
Prices based on models		-		-		-		2		5		7
Total	$	3	$	2	$	2	$	2	$	5	$	14

⁽¹⁾ For the last two quarters of 2005.
⁽²⁾ Broker quote sheets.

JCP&L performs sensitivity analyses to estimate its exposure to the market risk of its commodity position. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of June 30, 2005.

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their current market value of approximately $79 million and $80 million as of June 30, 2005 and December 31, 2004, 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, 2005.

Regulatory Matters

Regulatory assets are costs which have been authorized by the NJBPU and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. JCP&L's regulatory assets as of June 30, 2005 and December 31, 2004 were $2.1 billion and $2.2 billion, respectively.

An annual increase in distribution revenues of $23 million effective June 1, 2005, associated with the Phase I Order reconsideration;

An annual increase in distribution revenues of $36 million effective June 1, 2005, related to JCP&L's Phase II Petition;

An increase in JCP&L's authorized return on common equity from 9.5% to 9.75%; and

125

The Phase II stipulation included an agreement that the distribution revenues increase reflects a three-year amortization of JCP&L's service reliability improvement costs incurred in 2003-2005. This resulted in the creation of a regulatory asset associated with the accelerated reliability costs which were expensed in 2003 and 2004. The establishment of the new regulatory asset of approximately $28 million resulted in an increase to net income of approximately $16 million in the second quarter of 2005.

JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balance with the exception of 300 MW from JCP&L's NUG committed supply currently being used to serve BGS customers pursuant to NJBPU order. New BGS tariffs reflecting the results of a February 2005 auction for the BGS supply became effective June 1, 2005. On May 5, 2005, the NJBPU issued an order that BGS procurement proposals for post transition year four be filed by July 1, 2005. The NJBPU requested that the filings address transmission rate issues and rate design alternatives. JCP&L filed its proposal on July 1, 2005. The next auction is scheduled to take place in February 2006 for the supply period beginning June 1, 2006.

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. On March 29, 2004, the NJBPU adopted a Memorandum of Understanding (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 and 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 (Focused Audit). A Final Order in the Focused Audit docket was issued by the NJBPU on July 23, 2004. On February 11, 2005, JCP&L met with the Ratepayer Advocate to discuss reliability improvements. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.

On January 31, 2005, certain PJM transmission owners made three filings pursuant to a settlement agreement previously approved by the FERC. JCP&L was a party 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. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On June 30, 2005, the PJM transmission owners filed a request for rehearing of the May 31, 2005 order.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in New Jersey.

Environmental Matters

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

JCP&L has been named as a PRP 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, 2005, based on estimates of the total costs of cleanup, JCP&L's proportionate responsibility for such costs and the financial ability of other nonaffiliated 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. Included in Other Noncurrent Liabilities are accrued liabilities aggregating approximately $47 million as of June 30, 2005.

126

Other Legal Proceedings

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to normal business operations pending against JCP&L. The most significant are described below.

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 concludes, 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 website (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 also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability 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, and therefore FirstEnergy has not accrued a liability as of June 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

127

New Accounting Standards and Interpretations

SFAS 154 - "Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3"

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in an income statement. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. JCP&L will adopt this standard effective January 1, 2006.

FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this Interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective no later than the end of fiscal years ending after December 15, 2005. Therefore, JCP&L will adopt this Interpretation in the fourth quarter of 2005. JCP&L is currently evaluating the effect this Interpretation will have on its financial statements.

EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In March 2004, the EITF reached a consensus on the application guidance for Issue 03-1. EITF 03-1 provides a model for determining when investments in certain debt and equity securities are considered other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair value and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective for periods beginning after June 15, 2004, were delayed indefinitely by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, JCP&L continues to evaluate its investments as required by existing authoritative guidance.

128

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	*(In thousands)*

OPERATING REVENUES	$	263,136		$	242,044		$	558,917		$	502,942

OPERATING EXPENSES AND TAXES:
Purchased power		131,670			131,266			281,763			274,722
Other operating costs		52,648			47,021			111,118			80,069
Provision for depreciation		11,377			9,824			22,898			19,722
Amortization of regulatory assets		25,286			22,949			53,907			48,446
General taxes		17,023			16,687			36,295			34,423
Income taxes		5,133			751			11,865			8,731
Total operating expenses and taxes		243,137			228,498			517,846			466,113

OPERATING INCOME		19,999			13,546			41,071			36,829

OTHER INCOME (net of income taxes)		6,989			6,116			13,438			11,642

NET INTEREST CHARGES:
Interest on long-term debt		9,385			12,238			18,945			22,385
Allowance for borrowed funds used during construction		(73	)		(72	)		(251	)		(143	)
Other interest expense		2,013			831			3,676			1,520
Net interest charges		11,325			12,997			22,370			23,762

NET INCOME		15,663			6,665			32,139			24,709

OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gain (loss) on derivative hedges		84			(6	)		168			(3,266	)
Unrealized loss on available for sale securities		-			(75	)		-			(53	)
Other comprehensive income (loss)		84			(81	)		168			(3,319	)
Income tax (benefit) related to other comprehensive income		35			(37	)		70			(28	)
Other comprehensive income (loss), net of tax		49			(44	)		98			(3,291	)

TOTAL COMPREHENSIVE INCOME	$	15,712		$	6,621		$	32,237		$	21,418

The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of
these statements.

129

METROPOLITAN EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)

	June 30,			December 31,
	2005			2004
	*(In thousands)*
ASSETS
UTILITY PLANT:
In service	$	1,814,049		$	1,800,569
Less - Accumulated provision for depreciation		704,247			709,895
		1,109,802			1,090,674
Construction work in progress		15,716			21,735
		1,125,518			1,112,409
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		221,600			216,951
Long-term notes receivable from associated companies		11,053			10,453
Other		29,079			34,767
		261,732			262,171
CURRENT ASSETS:
Cash and cash equivalents		120			120
Notes receivable from associated companies		14,830			18,769
Receivables -
Customers (less accumulated provisions of $4,109,000 and $4,578,000,
respectively, for uncollectible accounts)		125,135			119,858
Associated companies		10,362			118,245
Other		7,889			15,493
Prepayments and other		32,262			11,057
		190,598			283,542
DEFERRED CHARGES:
Goodwill		867,649			869,585
Regulatory assets		673,366			693,133
Other		24,015			24,438
		1,565,030			1,587,156
	$	3,142,878		$	3,245,278
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity -
Common stock, without par value, authorized 900,000 shares -
859,500 shares outstanding	$	1,290,287		$	1,289,943
Accumulated other comprehensive loss		(43,392	)		(43,490	)
Retained earnings		37,106			38,966
Total common stockholder's equity		1,284,001			1,285,419
Long-term debt and other long-term obligations		694,122			701,736
		1,978,123			1,987,155
CURRENT LIABILITIES:
Currently payable long-term debt		-			30,435
Short-term borrowings -
Associated companies		34,021			80,090
Other		67,000			-
Accounts payable -
Associated companies		32,941			88,879
Other		31,442			26,097
Accrued taxes		6,773			11,957
Accrued interest		10,731			11,618
Other		18,106			23,076
		201,014			272,152
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		316,005			305,389
Accumulated deferred investment tax credits		10,456			10,868
Power purchase contract loss liability		317,602			349,980
Nuclear fuel disposal costs		38,900			38,408
Asset retirement obligation		137,074			132,887
Retirement benefits		79,014			82,218
Other		64,690			66,221
		963,741			985,971
COMMITMENTS AND CONTINGENCIES (Note 13)
	$	3,142,878		$	3,245,278


The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral
part of these balance sheets.

130

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	*(In thousands)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	15,663		$	6,665		$	32,139		$	24,709
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation		11,377			9,824			22,898			19,722
Amortization of regulatory assets		25,286			22,949			53,907			48,446
Deferred costs recoverable as regulatory assets		(13,571	)		(13,195	)		(30,012	)		(29,987	)
Deferred income taxes and investment tax credits, net		(1,887	)		(7,952	)		(1,898	)		(5,519	)
Accrued retirement benefit obligation		(1,556	)		(309	)		(3,203	)		765
Accrued compensation, net		407			186			(1,316	)		(448	)
Decrease (increase) in operating assets -
Receivables		40,498			26,775			110,210			32,542
Materials and supplies		-			18			(18	)		36
Prepayments and other current assets		12,930			7,293			(21,187	)		(29,325	)
Increase (decrease) in operating liabilities -
Accounts payable		(1,002	)		(12,169	)		(50,593	)		(5,321	)
Accrued taxes		4,487			(4,564	)		(5,184	)		(6,110	)
Accrued interest		286			7,344			(887	)		2,879
Other		(7,228	)		6,040			(16,362	)		(2,225	)
Net cash provided from operating activities		85,690			48,905			88,494			50,164

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			-			-			247,607
Short-term borrowings, net		(7,656	)		-			20,931			-
Redemptions and Repayments-
Long-term debt		(37,395	)		(100,000	)		(37,830	)		(150,435	)
Short-term borrowings, net		-			-			-			(65,335	)
Dividend Payments-
Common stock		(25,000	)		(20,000	)		(34,000	)		(25,000	)
Net cash provided from (used for) financing activities		(70,051	)		(120,000	)		(50,899	)		6,837

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(18,196	)		(12,381	)		(34,395	)		(21,343	)
Contributions to nuclear decommissioning trusts		(2,371	)		(2,371	)		(4,742	)		(4,742	)
Loan repayments from (loans to) associated companies, net		6,489			85,767			3,339			(31,035	)
Other		(1,561	)		80			(1,797	)		118
Net cash provided from (used for) investing activities		(15,639	)		71,095			(37,595	)		(57,002	)

Net change in cash and cash equivalents		-			-			-			(1	)
Cash and cash equivalents at beginning of period		120			120			120			121
Cash and cash equivalents at end of period	$	120		$	120		$	120		$	120

The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of
these statements.

131

Report of Independent Registered Public Accounting Firm

To the Stockholders 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, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

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, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(G) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 6 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

July 29, 2005

132

METROPOLITAN EDISON COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

Met-Ed is a wholly owned, electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also provides generation service to those customers electing to retain Met-Ed as their power supplier. Met-Ed has unbundled the price for electricity into its component elements - including generation, transmission, distribution and transition charges. Met-Ed continues to deliver power to homes and businesses through its existing distribution system.

Results of Operations

Net income increased to $16 million for the second quarter of 2005 from $7 million in the second quarter of 2004. For the first six months of 2005, net income increased to $32 million from $25 million in the same period of 2004. The increase in net income for both periods reflects higher operating revenues and other income, and lower interest charges. Partially offsetting these items for both periods were increased operating expenses and taxes as discussed below.

Operating revenues increased by $21 million, or 8.7%, in the second quarter of 2005 and by $56 million, or 11.1%, in the first six months of 2005, compared with the same periods of 2004. Increases in both periods were due in part to higher retail generation electric revenues from all customer sectors ($9 million for the quarter and $24 million for the first six months). The increase in retail generation KWH sales in both periods of 2005 are mainly attributable to weather and lower customer shopping -- primarily in the industrial sector. Shopping by industrial customers decreased by 10.8% and 14.3% in the second quarter and first six months of 2005, respectively. While the higher generation sales in the second quarter were offset by slightly lower composite unit prices, overall higher composite unit prices in the six-month period further contributed to the increase in generation revenues.

Revenues from distribution throughput increased by $4 million in the second quarter and by $10 million in the first six months of 2005 compared with the respective prior year periods. Both increases were due to higher KWH deliveries and higher unit prices. Also contributing to the higher operating revenues was an increase in transmission revenues of $6 million in the second quarter and $16 million in the first six months of 2005. This increase was due to a change in the power supply agreement with FES in the second quarter of 2004. That change also resulted in higher transmission expenses as discussed further below. Operating revenues also included a $4 million payment received in the first six months of 2005 under a contract provision associated with the prior sale of TMI Unit 1. Under the contract, additional payments are received if subsequent energy prices rise above specific levels and are credited to Met-Ed’s customers, resulting in no net impact to current earnings.

Changes in kilowatt-hour sales by customer class in the second quarter and first six months of 2005 compared to the same periods of 2004 are summarized in the following table:

	Three			Six
Changes in KWH Sales	Months			Months
Increase (Decrease)
Retail Electric Generation:
Residential		5.1	%		3.4	%
Commercial		5.6	%		6.3	%
Industrial		13.0	%		21.8	%
Total Retail Electric Generation Sales		7.4	%		8.8	%

Distribution Deliveries:
Residential		5.0	%		3.4	%
Commercial		4.2	%		4.8	%
Industrial		(1.2	)%		1.3	%
Total Distribution Deliveries		2.7	%		3.2	%

133

Operating Expenses and Taxes

Total operating expenses and taxes increased by $15 million in the second quarter and by $52 million in the first six months of 2005 compared with the same periods of 2004. The following table presents changes from the prior year by expense category:

	Three		Six
Operating Expenses and Taxes - Increases	Months		Months
	*(In millions)*
Purchased power costs	$	-	$	7
Other operating costs		6		31
Provision for depreciation		2		3
Amortization of regulatory assets		2		6
General taxes		1		2
Income taxes		4		3
Net increase in operating expenses and taxes	$	15	$	52

Purchased power costs increased in both second quarter and first six months of 2005 as a result of higher two-party power purchases ($27 million in the second quarter and $45 million in the first six months of 2005) and NUG contract purchases ($6 million in the second quarter and $8 million in the first six months of 2005), offset by a reduction in purchased power from FES ($33 million in the second quarter and $46 million in the first six months of 2005). The net increase in KWH purchases for both periods was required to meet higher retail generation demand.

Other operating costs increased in the second quarter and first six months of 2005 primarily due to higher PJM congestion charges and transmission expenses. The transmission expense increase for both periods resulted from the change in the power supply agreement with FES as discussed above.

Depreciation expense increased in the second quarter and first six months of 2005 due to an increase in the asset base. Depreciation expense also increased for the first six months due to higher estimated costs to decommission the Saxton nuclear plant. For both periods of 2005, regulatory asset amortization reflected increases associated with the level of CTC revenue recovery, partially offset by lower amortization related to above market NUG costs as compared to the prior year periods.

General taxes increased $2 million in the first six months of 2005 as the result of higher gross receipt taxes.

Capital Resources and Liquidity

Met-Ed’s cash requirements in 2005 and thereafter, for operating expenses, construction expenditures and scheduled debt maturities are expected to be met with a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

As of June 30, 2005 and December 31, 2004, Met-Ed had $120,000 of cash and cash equivalents.

Cash Flows From Operating Activities

Cash provided from operating activities in 2005 and 2004 were as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Operating Cash Flows	2005		2004		2005		2004
	*(In millions)*

Cash earnings ^(*)	$	36	$	19	$	73	$	58
Working capital and other		50		30		16		(8	)
Total cash flows form operating activities	$	86	$	49	$	89	$	50

^(*) Cash earnings is a non-GAAP measure (see reconciliation below).

Cash earnings (in the table above) is not a measure of performance calculated in accordance with GAAP. Met-Ed believes that cash earnings is a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.

134

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Reconciliation of Cash Earnings	2005			2004			2005			2004
	*(In millions)*

Net income (GAAP)	$	16		$	7		$	32		$	25
Non-cash charges (credits):
Provision for depreciation		11			10			23			20
Amortization of regulatory assets		25			23			54			48
Deferred costs recoverable as regulatory assets		(14	)		(13	)		(30	)		(30	)
Deferred income taxes and investment tax credits, net		(2	)		(8	)		(2	)		(5	)
Other non-cash charges		-			-			(4	)		-
Cash earnings (Non-GAAP)	$	36		$	19		$	73		$	58

The $17 million and $15 million increases in cash earnings for the second quarter and first six months of 2005, respectively, are described above under "Results of Operations". The $20 million increase in working capital in the second quarter of 2005 primarily resulted from changes of $14 million in accounts receivable, $11 million in accounts payable, and $9 million in accrued taxes, partially offset by a change of $7 million in accrued interest. The $24 million increase in working capital for the first six months of 2005 primarily resulted from changes of $78 million in accounts receivable, partially offset by changes of $45 million in accounts payable and $4 million in accrued interest.

Cash Flows From Financing Activities

For the second quarter of 2005, net cash used for financing activities was $70 million compared to $120 million in the second quarter of 2004. The $50 million decrease resulted primarily from a reduction in debt redemptions -- $37 million in the second quarter of 2005 compared to $100 million in the second quarter of 2004 - partially offset by an $8 million increase in repayments on short-term borrowings and a $5 million increase in common stock dividends to FirstEnergy. For the first six months of 2005, net cash used for financing activities was $51 million compared to $7 million of net cash provided from financing activities in the same period of 2004. The $58 million change in the six month period reflected new financings of $21 million (net short-term borrowings) in the first six months of 2005 compared to $247 million (long-term debt) in the same period of 2004. This change was partially offset by $38 million of debt redemptions in the first six months of 2005 compared to $216 million of debt redemptions in the first six months of 2004. In addition, common stock dividends to FirstEnergy increased by $9 million in the first six months of 2005.

As of June 30, 2005, Met-Ed had approximately $15 million of cash and temporary investments (including short-term notes receivable from associated companies) and $101 million of short-term borrowings outstanding. Met-Ed has authorization from the SEC to incur short-term debt up to $250 million (including the utility money pool). Under the terms of Met-Ed’s senior note indenture, no more first mortgage bonds can be issued as long as the senior bonds are outstanding. Met-Ed had no restrictions on the issuance of preferred stock.

Met-Ed Funding LLC (Met-Ed Funding), a wholly owned subsidiary of Met-Ed, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Met-Ed. Met-Ed Funding can borrow up to $80 million under a receivables financing arrangement. As a separate legal entity with separate creditors, Met-Ed Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Met-Ed. As of June 30, 2005, the facility was drawn for $67 million. On July 15, 2005, the facility was renewed until June 29, 2006. The annual facility fee is 0.25% on the entire finance limit.

Met-Ed has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of such a 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 second quarter of 2005 was 2.93%.

On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as borrowers, entered into a syndicated $2 billion five-year revolving credit facility. Borrowings under the facility are available to each borrower separately and will mature on the earlier of 364 days from the date of borrowing and the commitment termination date, as the same may be extended. Met-Ed’s borrowing limit under the facility is $250 million.

Met-Ed’s access to capital markets and costs of financing are dependent on the ratings of its securities and that of FirstEnergy. The ratings outlook on all securities is positive.

135

On May 1, 2005, Met-Ed redeemed all of its outstanding shares of 6.00% Series Pollution Control Revenue Bonds at par, plus accrued interest to the date of redemption.

Cash Flows From Investing Activities

In the second quarter of 2005, net cash used for investing activities totaled $16 million, compared to $71 million of net cash provided from investing activities in the second quarter of 2004. The change in the second quarter resulted from an $79 million decrease in loan repayments from associated companies and a $6 million increase in property additions. In the first six months of 2005, net cash used for investing activities totaled $38 million, compared to $57 million in the first six months of 2004. The decrease in the first six months of 2005 resulted from a $34 million increase in loan repayments from associated companies, partially offset by a $13 million increase in property additions. Expenditures for property additions primarily support Met-Ed’s energy delivery operations.

Met-Ed's capital spending for the period 2005 through 2007 is expected to be about $205 million for property additions, of which approximately $66 million applies to 2005. During the remaining two quarters of 2005, capital requirements for property additions are expected to be about $32 million. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. Met-Ed has no additional requirements for maturing long-term debt during the remainder of 2005.

Market Risk Information

Met-Ed 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 management to risk management activities throughout the Company.

Commodity Price Risk

Met-Ed is exposed to market risk primarily resulting from fluctuating electricity and natural gas prices. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including options and futures contracts. The derivatives are used for hedging purposes. Most of Met-Ed's non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. As of June 30, 2005, Met-Ed’s commodity derivative contract was an embedded option with a fair value of $27 million. A decrease of $5 million in the value of this asset was recorded as a decrease in regulatory liabilities, and therefore, had no impact on net income.

136

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, Met-Ed relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Met-Ed uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for valuation of derivative contracts as of June 30, 2005 are summarized by year in the following table:

Sources of Information -
Fair Value by Contract Year	2005⁽¹⁾		2006		2007		2008		2009		Thereafter		Total


Prices based on external sources⁽²⁾	$	5	$	6	$	6	$	-	$	-	$	-	$	17
Prices based on models		-		-		-		4		3		3		10
Total	$	5	$	6	$	6	$	4	$	3	$	3	$	27

⁽¹⁾ For the last two quarters of 2005. ⁽²⁾ Broker quote sheets.

Met-Ed 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 derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of June 30, 2005.

Equity Price Risk

Included in Met-Ed's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $134 million as of June 30, 2005 and December 31, 2004. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $13 million reduction in fair value as of June 30, 2005.

Regulatory Matters

Regulatory assets are costs which have been authorized by the PPUC and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. Met-Ed's regulatory assets as of June 30, 2005 and December 31, 2004 were $673 million and $693 million, respectively.

Met-Ed purchases a portion of its PLR requirements from FES through a wholesale power sales agreement. The PLR sale is automatically extended for each successive calendar year unless either party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES retains the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed under its NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's exposure to high wholesale power prices by providing power at a fixed price for its uncommitted PLR energy costs during the term of the agreement with FES. Met-Ed is authorized to defer differences between NUG contract costs and current market prices.

On January 12, 2005, Met-Ed filed a request with the PPUC for deferral of transmission-related costs beginning January 1, 2005, estimated to be approximately $4 million per month.

137

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania including a more detailed discussion of reliability initiatives, including actions by the PPUC, that impact Met-Ed.

Environmental Matters

Met-Ed accrues environmental liabilities when it concludes that it is probable that it has an obligation for such costs and can reasonably determine the amount of such costs. Unasserted claims are reflected in Met-Ed's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

Met-Ed has been named a PRP 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, 2005, based on estimates of the total costs of cleanup, Met-Ed's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. Included in Other Noncurrent Liabilities are accrued liabilities aggregating approximately $47,000 as of June 30, 2005.

Other Legal Proceedings

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to Met-Ed's normal business operations pending against Met-Ed. The most significant are described below.

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 concludes, 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 website (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 also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability 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, and therefore FirstEnergy has not accrued a liability as of June 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

138

New Accounting Standards and Interpretations

SFAS 154 - "Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3"

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in an income statement. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Met-Ed will adopt this Statement effective January 1, 2006.

FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective no later than the end of fiscal years ending after December 15, 2005. Therefore, Met-Ed will adopt this Interpretation in the fourth quarter of 2005. Met-Ed is currently evaluating the effect this Interpretation will have on its financial statements.

EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In March 2004, the EITF reached a consensus on the application guidance for Issue 03-1. EITF 03-1 provides a model for determining when investments in certain debt and equity securities are considered other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair value and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective for periods beginning after June 15, 2004, were delayed indefinitely by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, Met-Ed continues to evaluate its investments as required by existing authoritative guidance.

139

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	*(In thousands)*

OPERATING REVENUES	$	262,097		$	242,202		$	556,026		$	498,647

OPERATING EXPENSES AND TAXES:
Purchased power		139,292			139,452			289,549			295,828
Other operating costs		62,794			45,980			116,607			85,888
Provision for depreciation		12,479			11,510			24,985			22,948
Amortization of regulatory assets		13,118			13,720			26,303			27,371
General taxes		16,134			16,920			34,340			33,882
Income taxes		2,300			1,744			18,092			4,307
Total operating expenses and taxes		246,117			229,326			509,876			470,224

OPERATING INCOME		15,980			12,876			46,150			28,423

OTHER INCOME (EXPENSE) (net of income taxes)		(316	)		447			420			363

NET INTEREST CHARGES:
Interest on long-term debt		7,423			7,568			14,882			15,015
Allowance for borrowed funds used during construction		(264	)		(62	)		(389	)		(132	)
Deferred interest		-			-			-			190
Other interest expense		2,668			2,768			4,856			5,005
Net interest charges		9,827			10,274			19,349			20,078

NET INCOME		5,837			3,049			27,221			8,708

OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gain (loss) on derivative hedges		16			(635	)		32			(635	)
Unrealized loss on available for sale securities		(18	)		(18	)		(21	)		(10	)
Other comprehensive income (loss)		(2	)		(653	)		11			(645	)
Income tax benefit related to other comprehensive income		6			5			-			2
Other comprehensive income (loss), net of tax		4			(648	)		11			(643	)

TOTAL COMPREHENSIVE INCOME	$	5,841		$	2,401		$	27,232		$	8,065

The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of
these statements.

140

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,			December 31,
	2005			2004
	*(In thousands)*
ASSETS
UTILITY PLANT:
In service	$	1,979,489		$	1,981,846
Less - Accumulated provision for depreciation		763,857			776,904
		1,215,632			1,204,942
Construction work in progress		23,471			22,816
		1,239,103			1,227,758
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		109,484			109,620
Non-utility generation trusts		96,968			95,991
Long-term notes receivable from associated companies		14,342			14,001
Other		14,719			18,746
		235,513			238,358
CURRENT ASSETS:
Cash and cash equivalents		35			36
Notes receivable from associated companies		-			7,352
Receivables -
Customers (less accumulated provisions of $4,102,000 and $4,712,000,
respectively, for uncollectible accounts)		119,927			121,112
Associated companies		23,671			97,528
Other		8,218			12,778
Prepayments and other		29,305			7,198
		181,156			246,004
DEFERRED CHARGES:
Goodwill		886,559			888,011
Regulatory assets		183,075			200,173
Other		12,486			13,448
		1,082,120			1,101,632
	$	2,737,892		$	2,813,752
CAPITALIZATION AND LIABILITIES
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		1,206,351			1,205,948
Accumulated other comprehensive loss		(52,802	)		(52,813	)
Retained earnings		43,289			46,068
Total common stockholder's equity		1,302,650			1,305,015
Long-term debt and other long-term obligations		478,807			481,871
		1,781,457			1,786,886
CURRENT LIABILITIES:
Currently payable long-term debt		8,017			8,248
Short-term borrowings -
Associated companies		65,888			241,496
Other		139,000			-
Accounts payable -
Associated companies		29,825			56,154
Other		31,956			25,960
Accrued taxes		18,727			7,999
Accrued interest		9,661			9,695
Other		18,384			23,750
		321,458			373,302
NONCURRENT LIABILITIES:
Power purchase contract loss liability		336,696			382,548
Asset retirement obligation		68,537			66,443
Accumulated deferred income taxes		58,327			37,318
Retirement benefits		120,151			118,247
Other		51,266			49,008
		634,977			653,564
COMMITMENTS AND CONTINGENCIES (Note 13)
	$	2,737,892		$	2,813,752

The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part
of these balance sheets.

141

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	*(In thousands)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	5,837		$	3,049		$	27,221		$	8,708
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation		12,479			11,510			24,985			22,948
Amortization of regulatory assets		13,118			13,720			26,303			27,371
Deferred costs recoverable as regulatory assets		(16,513	)		(18,511	)		(35,946	)		(36,504	)
Deferred income taxes and investment tax credits, net		201			(23,508	)		2,647			1,734
Accrued retirement benefit obligations		1,037			839			1,905			3,641
Accrued compensation, net		244			(878	)		(2,386	)		1,377
Decrease (increase) in operating assets -
Receivables		40,457			65,624			79,602			53,495
Prepayments and other current assets		13,012			12,104			(22,107	)		(34,950	)
Increase (decrease) in operating liabilities -
Accounts payable		3,901			(4,022	)		(20,333	)		(14,760	)
Accrued taxes		523			(1,091	)		10,728			(7,574	)
Accrued interest		(5,615	)		(5,385	)		(34	)		(2,749	)
Other		4,582			20,635			4,365			24,289
Net cash provided from operating activities		73,263			74,086			96,950			47,026

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing -
Long-term debt		-			-			-			150,000
Short-term borrowings, net		-			68,962			-			7,636
Redemptions and Repayments -
Long-term debt		(3,508	)		(125,108	)		(3,521	)		(125,212	)
Short-term borrowings, net		(34,805	)		-			(36,608	)		-
Dividend Payments -
Common stock		(25,000	)		(5,000	)		(30,000	)		(5,000	)
Net cash provided from (used for) financing activities		(63,313	)		(61,146	)		(70,129	)		27,424

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(18,290	)		(12,042	)		(33,683	)		(23,236	)
Non-utility generation trust contribution		-			-			-			(50,614	)
Loan repayments from (loans to) associated companies, net		10,093			51			7,011			(20	)
Other, net		(1,753	)		(949	)		(150	)		(580	)
Net cash used for investing activities		(9,950	)		(12,940	)		(26,822	)		(74,450	)

Net change in cash and cash equivalents		-			-			(1	)		-
Cash and cash equivalents at beginning of period		35			36			36			36
Cash and cash equivalents at end of period	$	35		$	36		$	35		$	36

The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of
these statements.

142

Report of Independent Registered Public Accounting Firm

To the Stockholders 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, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

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, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(G) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 6 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

July 29, 2005

143

PENNSYLVANIA ELECTRIC COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern, western and south central Pennsylvania, providing regulated transmission and distribution services. Penelec also provides generation services to those customers electing to retain Penelec as their power supplier. Penelec has unbundled the price for electricity into its component elements - including generation, transmission, distribution and transition charges.

Results of Operations

Net income in the second quarter of 2005 increased to $6 million, compared to $3 million in the second quarter of 2004. The increase resulted from higher operating revenues that were partially offset by higher operating costs - primarily transmission expenses. During the first six months of 2005, net income increased to $27 million compared to $9 million in the first six months of 2004. The increase resulted from higher operating revenues and lower purchased power costs, partially offset by higher operating costs and income taxes.

Operating revenues increased by $20 million in the second quarter of 2005 compared to the second quarter of 2004, primarily due to higher transmission revenues. Transmission revenues increased $20 million as a result of a change in the power supply agreement with FES in the second quarter of 2004. The change also resulted in higher transmission expenses as discussed further below.

Operating revenues increased by $57 million in the first six months of 2005 compared to the first six months of 2004, primarily due to higher transmission, retail generation and distribution revenues. Transmission revenues increased $43 million as a result of the power supply agreement change with FES.

Total retail sales increased $11 million due to higher retail generation revenues of $9 million and distribution revenues of $2 million, respectively. Retail generation revenues increased, principally from increased generation KWH sales to all customer sectors (residential - $2 million; industrial - $4 million and commercial - $3 million) reflecting increases in KWH sales of 1.9%, 3.7% and 2.7%, respectively, combined with higher unit costs. Industrial KWH sales increased despite a small increase in customer shopping. Sales by alternative suppliers as a percent of total industrial sales delivered in Penelec’s franchise area increased by 0.7%, while residential and commercial customer shopping remained constant in the first six months of 2005 compared to the same period of 2004.

Distribution revenues increased by $2 million in the first six months of 2005 compared to the same period of 2004, primarily due to higher deliveries in all sectors. Residential and commercial revenues increased by $1 million each as a result of higher KWH deliveries, partially offset by lower composite unit prices.

Changes in kilowatt-hour sales by customer class in the second quarter and first six months of 2005 compared to the respective periods in 2004 are summarized in the following table:

	Three			Six
Changes in KWH Sales	Months			Months
Increase (Decrease)
Distribution Deliveries:
Residential		3.8	%		1.9	%
Commercial		(1.4	)%		2.7	%
Industrial		(8.2	)%		3.7	%
Total Distribution Deliveries		(2.5	)%		2.8	%

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Operating Expenses and Taxes

Total operating expenses and taxes increased by $17 million or 7.3% in the second quarter and $40 million or 8.4% in the first six months of 2005 compared with the same periods in 2004. The following table presents changes from the prior year by expense category:

	Three			Six
Operating Expenses and Taxes - Changes	Months			Months
	*(In millions)*
Increase (Decrease)
Purchased power costs	$	-		$	(6	)
Other operating costs		17			31
Provision for depreciation		1			2
Amortization of regulatory assets		(1	)		(1	)
General taxes		(1	)		-
Income taxes		1			14
Net increase in operating expenses and taxes	$	17		$	40

Other operating costs increased by $17 million or 36.5% in the second quarter and $31 million or 35.7% in the first six months of 2005 compared to same periods in 2004. The increases in both periods were primarily due to increased transmission expenses in 2005 as a result of the change in the power supply agreement with FES as discussed above. In addition, there were higher costs of $2 million and $4 million associated with a low-income customer program in the second quarter and the first six months of 2005, respectively. Purchased power costs decreased by $6 million in the first half of 2005 compared to the first half of 2004 primarily due to lower unit costs, partially offset by increased KWH purchased to meet increased retail generation sales requirements. Income taxes increased due to higher operating income in the second quarter and first six months of 2005 compared to the same periods of 2004.

Capital Resources and Liquidity

Penelec’s cash requirements for operating expenses, construction expenditures and scheduled debt maturities are expected to be met by a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

As of June 30, 2005, Penelec had $35,000 of cash and cash equivalents compared with $36,000 as of December 31, 2004. The major sources for changes in these balances are summarized below.

Cash Flows From Operating Activities

Net cash provided from operating activities in the second quarter and first six months of 2005, compared with the corresponding periods in 2004, are summarized as follows:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
Operating Cash Flows	2005		2004			2005		2004
	*(In millions)*

Cash earnings ^(*)	$	17	$	(14	)	$	45	$	29
Working capital and other		56		88			52		18
Total cash flows from operating activities	$	73	$	74		$	97	$	47

^(*) Cash earnings is a non-GAAP measure (see reconciliation below).

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Cash earnings (in the table above) are not a measure of performance calculated in accordance with GAAP. Penelec believes that cash earnings is a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Reconciliation of Cash Earnings	2005			2004			2005			2004
	*(In millions)*

Net income (GAAP)	$	6		$	3		$	27		$	9
Non-cash charges (credits):
Provision for depreciation		13			11			25			23
Amortization of regulatory assets		13			14			26			27
Deferred costs recoverable as regulatory assets		(16	)		(19	)		(36	)		(37	)
Deferred income taxes and investment tax credits, net		-			(23	)		3			2
Other non-cash items		1			-			-			5
Cash earnings (Non-GAAP)	$	17		$	(14	)	$	45		$	29

Net cash provided from cash earnings increased by $31 million in the second quarter and $16 million in the first six months of 2005 compared to the same periods of 2004. These increases in cash earnings are described above and under åResults of Operationsæ. The $32 million decrease in working capital primarily resulted from changes in receivables, and customer deposits, partially offset by changes in accounts payable and accrued taxes. Working capital increased by $34 million in the first six months of 2005 principally due to changes in receivables, prepayments and accrued taxes, partially offset by changes accounts payable and customer deposits.

Cash Flows From Financing Activities

Net cash used for financing activities was $63 million in the second quarter of 2005 compared to $61 million in the second quarter of 2004. The net change reflects a $20 million increase in common stock dividends to FirstEnergy and a $104 million increase in repayments of short-term borrowings, offset by a $122 million decrease in debt redemptions.

On May 1, 2005 Penelec redeemed all of its outstanding shares of 6.125% Series B Pollution Control Revenue Bonds at par, plus accrued interest to date of redemption.

Net cash used for financing activities was $70 million for the first six months of 2005 compared to net cash provided from financing activities of $27 million in the first six months of 2004. The net change of $97 million reflects the absence of a $150 million long-term debt financing in 2004, a $25 million increase in common stock dividends to FirstEnergy and a $44 million increase in repayments of short-term borrowings, offset by a $122 million decrease in debt redemptions.

Penelec had approximately $35,000 of cash and temporary investments (which include short-term notes receivable from associated companies) and approximately $205 million of short-term indebtedness as of June 30, 2005. Penelec has authorization from the SEC to incur short-term debt of up to $250 million (including the utility money pool). Penelec will not issue FMB other than as collateral for senior notes, since its senior note indentures prohibit (subject to certain exceptions) Penelec from issuing any debt which is senior to the senior notes. As of June 30, 2005, Penelec had the capability to issue $3 million of additional senior notes based upon FMB collateral. Penelec has no restrictions on the issuance of preferred stock.

Penelec Funding LLC (Penelec Funding), a wholly owned subsidiary of Penelec, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Penelec. Penelec Funding can borrow up to $75 million under a receivables financing arrangement. As a separate legal entity with separate creditors, Penelec Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Penelec. As of June 30, 2005, the facility was drawn for $64 million. On July 15, 2005, the facility was renewed until June 29, 2006. The annual facility fee is 0.25% on the entire finance limit.

Penelec has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal, 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 under these arrangements in the second quarter of 2005 was 2.93%.

146

Penelec’s access to capital markets and costs of financing are dependent on the ratings of its securities and that of FirstEnergy. On May 16, 2005, S&P affirmed its 'BBB-' corporate credit ratings on FirstEnergy Corp. and its units and revised its outlook on the companies to positive from stable. S&P stated that the rating affirmation and outlook revision reflects the successful restart of the three nuclear units from their respective outages that occurred during the first half of 2005. S&P noted that a subsequent rating upgrade could follow if FirstEnergy's financial performance continues to improve as projected and as the nuclear operations further stabilize.

On July 18, 2005, Moody’s revised its rating outlook for FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that revision to FirstEnergy’s rating outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the outlook recognized management’s regional strategy of focusing on its core utility businesses. FirstEnergy’s credit profile has been improving, with a significant debt reduction largely resulting from the application of free cash flow. Moody’s notes that a rating upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.

Cash Flows From Investing Activities

Cash used for investing activities was $10 million in the second quarter of 2005 compared to $13 million in the second quarter of 2004. The increase was primarily due to increased loan repayments from associated companies, partially offset by higher property additions. Cash used for investing activities was $27 million in the first six months of 2005 compared to $74 million in the first six months of 2005. The decrease was primarily due to the absence in 2005 of a $51 million repayment to the NUG trust fund in 2004 and increased loan repayments from associated companies, partially offset by increased property additions. Capital expenditures for property additions primarily support Penelec’s energy delivery operations.

Penelec’s capital spending for the period 2005-2007 is expected to be about $272 million for property additions and improvements, of which about $91 million applies to 2005. During the second half of 2005, capital requirements for property additions are expected to be about $55 million. Penelec has additional requirements of approximately $8 million for maturing long-term debt during the remainder of 2005. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements.

Market Risk Information

Penelec 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 management oversight to risk management activities throughout the Company.

Commodity Price Risk

Penelec is exposed to market risk primarily due to fluctuations in electricity and natural gas prices. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including options and futures contracts. The derivatives are used for hedging purposes. Penelec’s non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. As of June 30, 2005, Penelec’s commodity derivatives contract was an embedded option with a fair value of $14 million. A decrease of $1 million in the value of this asset was recorded in the first six months of 2005 as a decrease in regulatory liabilities, and therefore, had no impact on net income.

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The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, Penelec relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Penelec uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for valuation of derivative contracts as of June 30, 2005 are summarized by year in the following table:

Sources of Information -
Fair Value by Contract Year	2005⁽¹⁾		2006		2007		2008		2009		Thereafter		Total


Prices based on external sources⁽²⁾	$	3	$	2	$	2	$	-	$	-	$	-	$	7
Prices based on models		-		-		-		2		2		3		7
Total	$	3	$	2	$	2	$	2	$	2	$	3	$	14

⁽¹⁾ For the last two quarters of 2005.
⁽²⁾ Broker quote sheets.

Penelec 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 both its trading and nontrading derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of June 30, 2005.

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $59 million and $60 million as of June 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $6 million reduction in fair value as of June 30, 2005.

Regulatory Matters

Regulatory assets are costs which have been authorized by the PPUC and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. Penelec's regulatory assets as of June 30, 2005 and December 31, 2004 were $183 million and $200 million, respectively.

Penelec purchases a portion of its PLR requirements from FES through a wholesale power sales agreement. The PLR sale is automatically extended for each successive calendar year unless either party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES retains the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Penelec under its NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Penelec's exposure to high wholesale power prices by providing power at a fixed price for its uncommitted PLR energy costs during the term of the agreement with FES. Penelec is authorized to defer differences between NUG contract costs and current market prices.

On January 12, 2005, Penelec filed a request with the PPUC to defer transmission-related costs beginning January 1, 2005, estimated to be approximately $4 million per month.

On January 31, 2005, certain PJM transmission owners made three filings pursuant to a settlement agreement previously approved by the FERC. Penelec was a party 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. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On June 30, 2005, the PJM transmission owners filed a request for rehearing of the May 31, 2005 order.

148

Environmental Matters

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

Penelec has been named a PRP 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.

Other Legal Proceedings

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to Penelec's normal business operations pending against Penelec. The most significant are described below.

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 concludes, 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 website (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 also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability 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, and therefore FirstEnergy has not accrued a liability as of June 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

149

New Accounting Standards and Interpretations

SFAS 154 - "Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3"

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in an income statement. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Penelec will adopt this Statement effective January 1, 2006.

FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective no later than the end of fiscal years ending after December 15, 2005. Therefore, Penelec will adopt this Interpretation in the fourth quarter of 2005. Penelec is currently evaluating the effect this Interpretation will have on its financial statements.

EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In March 2004, the EITF reached a consensus on the application guidance for Issue 03-1. EITF 03-1 provides a model for determining when investments in certain debt and equity securities are considered other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair value and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective for periods beginning after June 15, 2004, were delayed indefinitely by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, Penelec continues to evaluate its investments as required by existing authoritative guidance.

150

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See "Management’s Discussion and Analysis of Results of Operation and Financial Condition - 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, as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e), as of the end of the date covered by the report. Based on that evaluation, those officers have concluded that the registrant's disclosure controls and procedures are effective in timely alerting them to any information relating to the registrants’ and their consolidated subsidiaries that is required to be included in the registrants’ periodic reports and in ensuring that information required in the reports filed under the Exchange Act is recorded, processed summarized and reported within the time period specified by the SEC's rules and forms.

(b) CHANGES IN INTERNAL CONTROLS

On April 1, 2005, FirstEnergy, the Ohio Companies and Penn implemented or modified certain internal controls over financial reporting to accommodate their participation in the launch of the MISO Day 2 wholesale energy markets for both day-ahead and real-time energy transmissions, as well as a financial transmission rights market for transmission capacity. MISO also started dispatching generating plants and providing real-time energy and balance services. The new or modified controls primarily relate to revenue and cost recognition associated with power sales and purchases in the MISO Day 2 markets. Management believes these controls are important for the accurate reporting of such amounts and, based upon management's testing, are adequate for such purposes. There were no other 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 during the quarter ended June 30, 2005.

151

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 13 and 14 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES

(e) FirstEnergy

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

							Maximum Number
							(or Approximate
					Total Number of		Dollar Value) of
					Shares Purchased		Shares that May
	Total Number				As Part of Publicly		Yet Be Purchased
	of Shares		Average Price		Announced Plans		Under the Plans
Period	Purchased (a)		Paid per Share		or Programs (b)		or Programs

April 1-30, 2005		449,813	$	42.53		-		-
May 1-31, 2005		940,490	$	43.75		-		-
June 1-30, 2005		1,103,335	$	46.34		-		-

Second Quarter 2005		2,493,638	$	44.68		-		-

(a)

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

(b)	FirstEnergy does not currently have any publicly announced plan or program for share purchases.

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

(a)	The annual meeting of FirstEnergy shareholders was held on May 17, 2005.

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

	Number of Votes
	For		Withheld

Anthony J. Alexander		280,505,194		5,433,413
Russell W. Maier		279,922,948		6,015,659
Robert N. Pokelwaldt		280,048,373		5,890,234
Wes M. Taylor		283,540,631		2,397,976
Jesse T. Williams, Sr.		279,999,208		5,939,399

The term of office for the following Directors continued after the shareholders meeting: Dr. Carol A. Cartwright, William T. Cottle, Paul J. Powers, George M. Smart, Dr. Patricia K. Woolf, Paul T. Addison, Ernest J. Novak, Jr., Catherine A. Rein 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 2004 was ratified:

Number of Votes
For	Against		Abstentions

281,532,886		1,685,722		2,719,999

(ii)

At this meeting, a shareholder proposal requesting that FirstEnergy publish semi-annual reports regarding its political contributions was not approved (approval required a majority of votes cast):

152

Number of Votes
					Broker
For	Against		Abstentions		Non-Votes

19,941,051		215,630,919		19,307,851		31,058,786

(iii)

At this meeting, a shareholder proposal recommending that the Board of Directors take steps for adoption of simple majority voting was approved (approval required a majority of votes cast):

Number of Votes
					Broker
For	Against		Abstentions		Non-Votes

178,017,001		71,654,202		5,208,721		31,058,683

Based on this result, the Board will further review this proposal and consider the appropriate steps to take in response.

(iv)

At this meeting, a shareholder proposal recommending that any matching awards under the Executive Deferred Compensation Plan be in the form of performance-based stock options was not approved (approval required a majority of the votes cast):

Number of Votes
					Broker
For	Against		Abstentions		Non-Votes

47,687,400		202,204,312		4,988,404		31,058,491

ITEM 6. EXHIBITS

(a) Exhibits

Exhibit
Number

JCP&L

	12	Fixed charge ratios
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	31.3	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	32.2	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

Met-Ed

	12	Fixed charge ratios
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	32.1	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-15(e)/15d-15(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

FirstEnergy

	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

OE

	4.1	Seventy-ninth Supplemental Indenture dated as of April 1, 2005 between OE and The Bank of New York, as successor Trustee under the Indenture dated as of August 1, 1930.

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	4.2	Eightieth Supplemental Indenture dated as of April 15, 2005 between OE and The Bank of New York, as successor Trustee under the Indenture dated as of August 1, 1930.
	4.3	Eighty-first Supplemental Indenture dated as of June 1, 2005 between OE and The Bank of New York, as successor Trustee under the Indenture dated as of August 1, 1930.
	4.4	Eleventh Supplemental Indenture dated as of April 1, 2005 between OE and The Bank of New York, as Trustee under the General Mortgage Indenture and Deed of Trust dated as of January 1, 1998.
	4.5	Twelfth Supplemental Indenture dated as of April 15, 2005 between OE and The Bank of New York, as Trustee under the General Mortgage Indenture and Deed of Trust dated as of January 1, 1998.
	4.6	Thirteenth Supplemental Indenture dated as of June 1, 2005 between OE and The Bank of New York, as Trustee under the General Mortgage Indenture and Deed of Trust dated as of January 1, 1998.
	10.1	OE Nuclear Capital Contribution Agreement by and between Ohio Edison Company and
		FirstEnergy Nuclear Generation Corp. (May 20, 2005 Form 8-K, Exhibit 10.1).
	10.2	OE Fossil Purchase and Sale Agreement by and between Ohio Edison Company (Seller) and
		FirstEnergy Generation Corp. (Purchaser). (May 20, 2005 Form 8-K, Exhibit 10.2).
	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

Penn

	10.1	PP Nuclear Subscription and Capital Contribution Agreement by and between Pennsylvania Power
		Company and FirstEnergy Nuclear Generation Corp. (May 20, 2005 Form 8-K, Exhibit 10.1).
	10.2	PP Fossil Purchase and Sale Agreement by and between Pennsylvania Power Company (Seller)
		and FirstEnergy Generation Corp. (Purchaser). (May 20, 2005 Form 8-K, Exhibit 10.2).
	15	Letter from independent registered public accounting firm.
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

CEI

	4.1	Eighty-seventh Supplemental Indenture dated as of April 1, 2005 between CEI and JPMorgan Chase Bank, N.A., as Trustee under the Mortgage and Deed of Trust dated as of July 1, 1940.
	4.2	Eighty-eighth Supplemental Indenture dated as of July 1, 2005 between CEI and JPMorgan Chase Bank, N.A., as Trustee under the Mortgage and Deed of Trust dated as of July 1, 1940.
	10.1	CEI Nuclear Purchase and Sale Agreement by and between The Cleveland Electric Illuminating
		Exhibit 10.1).
	10.2	CEI Fossil Purchase and Sale Agreement by and between The Cleveland Electric Illuminating Company
		(Seller) and FirstEnergy Generation Corp. (Purchaser). (May 20, 2005 Form 8-K, Exhibit 10.2).
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

TE

	4.1	Fifty-fifth Supplemental Indenture dated as of April 1, 2005 between TE and JPMorgan Chase Bank, N.A., as Trustee under the Indenture of Mortgage and Deed of Trust dated as of April 1, 1947.
	10.1	TE Nuclear Purchase and Sale Agreement by and between The Toledo Edison Company (Seller) and FirstEnergy Nuclear Generation Corp. (Purchaser). (May 20, 2005 Form 8-K, Exhibit 10.1).
	10.2	TE Fossil Purchase and Sale Agreement by and between The Toledo Edison Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (May 20, 2005 Form 8-K, Exhibit 10.2).
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

Pursuant to reporting requirements of respective financings, JCP&L, Met-Ed and Penelec are required to file fixed charge ratios as an exhibit to this Form 10-Q. FirstEnergy, OE, CEI, TE and Penn do not have similar financing reporting requirements and have not filed their respective fixed charge ratios.

Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, OE, CEI, TE, Penn, 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 their respective total assets of FirstEnergy and its subsidiaries on a consolidated basis, or respectively, OE, CEI, TE, Penn, JCP&L, Met-Ed or Penelec, but hereby agree to furnish to the Commission on request any such documents.

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SIGNATURE

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 1, 2005

	FIRSTENERGY CORP.
	Registrant

	OHIO EDISON COMPANY
	Registrant

	THE CLEVELAND ELECTRIC
	ILLUMINATING COMPANY
	Registrant

	THE TOLEDO EDISON COMPANY
	Registrant

	PENNSYLVANIA POWER COMPANY
	Registrant

	JERSEY CENTRAL POWER & LIGHT COMPANY
	Registrant

	METROPOLITAN EDISON COMPANY
	Registrant

	PENNSYLVANIA ELECTRIC COMPANY
	Registrant

	/s/ Harvey L. Wagner
	Harvey L. Wagner
	Vice President, Controller
	and Chief Accounting Officer

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Firstenergy Inactive 10-Q2005 Q2 Quarterly report

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