UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q ~~(Mark~~

(Mark One) ~~[X]~~

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

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, ~~2004~~ 2005

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

SECURITIES EXCHANGE ACT OF 1934 For the transition period from to ----------------- ------------------- Commission Registrant; State of Incorporation; I.R.S. Employer File Number Address; and Telephone Number Identification No. - ----------- ------------------------------------------ ------------------ 333-21011 FIRSTENERGY CORP. 34-1843785 (An Ohio Corporation) 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-2578 OHIO EDISON COMPANY 34-0437786 (An Ohio Corporation) 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

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.

YesXNo ~~---- -----~~

Indicate by check mark whether each registrant is an accelerated filer (as defined in Rule 12b-2 of the Act): ~~Yes (X) No ( ) FirstEnergy Corp. Yes ( ) No (X )~~

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, 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 MAY 7, 2004 ----- ----------------- 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

	OUTSTANDING
CLASS	AS OF MAY 2, 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 receipt of approval from and entry of a final order by the U.S. District Court, Southern District of Ohio, on the pending settlement agreement resolving the New Source Review litigation and 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 this settlement, adverse regulatory or legal decisions and ~~the outcome of governmental investigations~~outcomes (including revocation of necessary licenses or operating ~~permits),~~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, further investigation into the causes of the August 14, 2003 regional power ~~outage~~outages and the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to ~~that outage, a denial of or material change~~the outages, the final outcome in the proceeding related to FirstEnergy's Application ~~related to its~~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, ~~2003~~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.........................................~~

		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	1-18

FirstEnergy Corp.

	Consolidated Statements of Income	19
	Consolidated Statements of Comprehensive Income	20
	Consolidated Balance Sheets	21
	Consolidated Statements of Cash Flows	22
	Report of Independent Registered Public Accounting Firm	23
	Management's Discussion and Analysis of Results of Operations and
	Financial Condition	24-45

Ohio Edison Company

	Consolidated Statements of Income and Comprehensive Income	46
	Consolidated Balance Sheets	47
	Consolidated Statements of Cash Flows	48
	Report of Independent Registered Public Accounting Firm	49
	Management's Discussion and Analysis of Results of Operations and
	Financial Condition	50-58

The Cleveland Electric Illuminating Company

	Consolidated Statements of Income and Comprehensive Income	59
	Consolidated Balance Sheets	60
	Consolidated Statements of Cash Flows	61
	Report of Independent Registered Public Accounting Firm	62
	Management's Discussion and Analysis of Results of Operations and
	Financial Condition	63-71

The Toledo Edison Company

	Consolidated Statements of Income and Comprehensive Income	72
	Consolidated Balance Sheets	73
	Consolidated Statements of Cash Flows	74
	Report of Independent Registered Public Accounting Firm	75
	Management's Discussion and Analysis of Results of Operations and
	Financial Condition	76-83

Pennsylvania Power Company

	Consolidated Statements of Income and Comprehensive Income	84
	Consolidated Balance Sheets	85
	Consolidated Statements of Cash Flows	86
	Report of Independent Registered Public Accounting Firm	87
	Management's Discussion and Analysis of Results of Operations and
	Financial Condition	88-94

i - ii 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................ 1-19 FirstEnergy Corp. Consolidated Statements of Income......................... 20 Consolidated Balance Sheets............................... 21 Consolidated Statements of Cash Flows..................... 22 Report of Independent Accountants......................... 23 Management's Discussion and Analysis of Results of Operations and Financial Condition................... 24-48 Ohio Edison Company Consolidated Statements of Income......................... 49 Consolidated Balance Sheets............................... 50 Consolidated Statements of Cash Flows..................... 51 Report of Independent Accountants......................... 52 Management's Discussion and Analysis of Results of Operations and Financial Condition................... 53-62 The Cleveland Electric Illuminating Company Consolidated Statements of Income......................... 63 Consolidated Balance Sheets............................... 64 Consolidated Statements of Cash Flows..................... 65 Report of Independent Accountants......................... 66 Management's Discussion and Analysis of Results of Operations and Financial Condition................... 67-76 The Toledo Edison Company Consolidated Statements of Income......................... 77 Consolidated Balance Sheets............................... 78 Consolidated Statements of Cash Flows..................... 79 Report of Independent Accountants......................... 80 Management's Discussion and Analysis of Results of Operations and Financial Condition................... 81-90 Pennsylvania Power Company Consolidated Statements of Income......................... 91 Consolidated Balance Sheets............................... 92 Consolidated Statements of Cash Flows..................... 93 Report of Independent Accountants......................... 94 Management's Discussion and Analysis of Results of Operations and Financial Condition................... 95-101

TABLE OF CONTENTS (Cont'd) Pages Jersey Central Power & Light Company Consolidated Statements of Income......................... 102 Consolidated Balance Sheets............................... 103 Consolidated Statements of Cash Flows..................... 104 Report of Independent Accountants......................... 105 Management's Discussion and Analysis of Results of Operations and Financial Condition................... 106-114 Metropolitan Edison Company Consolidated Statements of Income......................... 115 Consolidated Balance Sheets............................... 116 Consolidated Statements of Cash Flows..................... 117 Report of Independent Accountants......................... 118 Management's Discussion and Analysis of Results of Operations and Financial Condition................... 119-127 Pennsylvania Electric Company Consolidated Statements of Income......................... 128 Consolidated Balance Sheets............................... 129 Consolidated Statements of Cash Flows..................... 130 Report of Independent Accountants......................... 131 Management's Discussion and Analysis of Results of Operations and Financial Condition................... 132-141 Item 3. Quantitative and Qualitative Disclosure About Market Risk................................ 142 Item 4. Controls and Procedures............................ 142 Part II Other Information Item 1. Legal Proceedings.................................. 143 Item 6. Exhibits and Reports on Form 8-K................... 143

		Pages


Jersey Central Power & Light Company

	Consolidated Statements of Income and Comprehensive Income	95
	Consolidated Balance Sheets	96
	Consolidated Statements of Cash Flows	97
	Report of Independent Registered Public Accounting Firm	98
	Management's Discussion and Analysis of Results of Operations and
	Financial Condition	99-105

Metropolitan Edison Company

	Consolidated Statements of Income and Comprehensive Income	106
	Consolidated Balance Sheets	107
	Consolidated Statements of Cash Flows	108
	Report of Independent Registered Public Accounting Firm	109
	Management's Discussion and Analysis of Results of Operations and
	Financial Condition	110-115

Pennsylvania Electric Company

	Consolidated Statements of Income and Comprehensive Income	116
	Consolidated Balance Sheets	117
	Consolidated Statements of Cash Flows	118
	Report of Independent Registered Public Accounting Firm	119
	Management's Discussion and Analysis of Results of Operations and
	Financial Condition	120-125

Item 3.Quantitative and Qualitative Disclosures About Market Risk		126

Item 4.Controls and Procedures		126

Part II. Other Information

Item 1.Legal Proceedings		127

Item 2.Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities		127

Item 6.Exhibits		130-142

GLOSSARY OF TERMS

The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its ~~subsidiaries: ATSI.....................American Transmission Systems, Inc., owns~~current and operates transmission facilities Avon.....................Avon Energy Partners Holdings CEI......................The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary CFC......................Centerior Funding Corporation, a wholly owned finance subsidiary of CEI Emdersa................ Empresa Distribuidora Electrica Regional S.A EUOC.....................Electric Utility Operating Companies, (OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec, 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 phone 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 GLEP.....................Great Lakes Energy Partners, LLC, an oil and natural gas exploration and production venture GPU......................GPU, Inc., former parent of Jersey Central Power & Light Copany, Metropolitan Edison Company and Pennsylvania Electric Company, which merged with FirstEnergy on November 7, 2001 GPU Capital..............GPU Capital, Inc., owned and operated electric distribution systems in foreign countries GPU Power................GPU Power, Inc., owned and operated generation facilities in foreign countries GPUS.....................GPU Service Company, previously provided corporate support services 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 MARBEL...................MARBEL Energy Corporation, holds FirstEnergy's interest in Great Lakes Energy Partners, LLC Met-Ed...................Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary MYR......................MYR Group, Inc., a utility infrastructure construction service company NEO......................Northeast Ohio Natural Gas Corp., a MARBEL subsidiary OE.......................Ohio Edison Company, an Ohio electric utility operating subsidiary OE Companies.............OE and Pennsylvania Power Company Penelec..................Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary Penn.....................Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary 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 subsidiaries:

ATSI	American Transmission Systems, Inc., 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
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

The following abbreviations and acronyms are used to identify frequently used terms in this report: TE.......................The Toledo Edison Company, an Ohio electric utility operating subsidiary TECC.....................Toledo Edison Capital Corporation, a 90% owned subsidiary of TE ALJ......................Administrative Law Judge AOCL.....................Accumulated Other Comprehensive Loss APB......................Accounting Principles Board APB 25...................APB No. 25, "Accounting for Stock Issued to Employees" ARO......................Asset Retirement Obligation BGS......................Basic Generation Service CO2......................Carbon Dioxide CTC......................Competitive Transition Charge ECAR.....................East Central Area Reliability Agreement EITF.....................Emerging Issues Task Force EITF 03-6................EITF Issue No. 03-6, "Participating Securities and the Two-Class Method Under Financial Accounting Standards Board Statement No. 128, Earnings per Share" 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 FASB Concepts No. 7......FASB Concepts Statement No. 7, "Using Cash Flow Information and Present Value in Accounting Measurements" FERC.....................Federal Energy Regulatory Commission FIN .....................FASB Interpretation FIN 46R..................FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" FSP......................FASB Staff Position i FSP 106-1................FASB Staff Position 106-1, "Accounting and Disclosure Requirements Related to the Medicare" Prescription Drug, Improvement and Modernization Act of 2003" GAAP.....................Accounting Principles Generally Accepted in the United States IRS......................Internal Revenue Service ISO......................Independent System Operator KWH......................Kilowatt-hours LOC......................Letter of Credit Medicare Act.............Medicare Prescription Drug, Improvement and Modernization Act of 2003 MISO.....................Midwest Independent System Operator, Inc. Moody's..................Moody's Investors Service 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 NOX......................Nitrogen Oxides NRC......................Nuclear Regulatory Commission NUG......................Non-Utility Generation OCI......................Other Comprehensive Income OPEB.....................Other Post-Employment Benefits PJM......................PJM Interconnection ISO PLR......................Provider of Last Resort PPUC.....................Pennsylvania Public Utility Commission PRP......................Potentially Responsible Party PUCO.....................Public Utilities Commission of Ohio S&P......................Standard & Poor's SBC......................Societal Benefits Charge SEC......................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 87..................SFAS No. 87, "Employers' Accounting for Pensions" SFAS 106.................SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" SFAS 123.................SFAS No. 123, "Accounting for Stock-Based Compensation" 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 142.................SFAS No. 142, "Goodwill and Other Intangible Assets" SFAS 143.................SFAS No. 143, "Accounting for Asset Retirement Obligations" SFAS 144.................SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" SFAS 150.................SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" SO2......................Sulfur Dioxide SPE......................Special Purpose Entity TBC......................Transition Bond Charge TEBSA....................Termobarranquilla S.A., Empresa de Servicios Publicos TMI-2....................Three Mile Island Unit 2 VIE......................Variable Interest Entity ii

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
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 SameCounterparty”
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 - aninterpretation of FASB Statement No. 143”
FMB	First Mortgage Bonds
FSP	FASB Staff Position
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"

iii

GLOSSARY OF TERMS Cont'd

FSP 109-1	FASB Staff Position No. 109-1,“Application of FASB Statement No. 109, Accounting for IncomeTaxes, to the Tax Deduction on Qualified Production Activities Provided by the American JobsCreation 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
NOV	Notices of Violation
NO_X	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
NUG	Non-Utility Generation
OCC	Ohio Consumers' Counsel
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
PCAOB	Public Company Accounting Oversight Board (United States)
PJM	PJM Interconnection L.L.C.
PLR	Provider of Last Resort
PPUC	Pennsylvania Public Utility Commission
PRP	Potentially Responsible Party
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"
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

1. - ORGANIZATION AND BASIS OF PRESENTATION: ~~The~~

FirstEnergy’s principal business ~~of FirstEnergy~~ 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. ~~These utility subsidiaries are referred to throughout as "Companies."~~ Penn is a wholly owned subsidiary of OE. JCP&L, Met-Ed and Penelec were acquired in a merger (which was effective November 7, 2001) with GPU, the former parent company of JCP&L, Met-Ed and Penelec. The merger was accounted for by the purchase method of accounting and the applicable effects were reflected on the financial statements of JCP&L, Met-Ed and Penelec as of the merger date. FirstEnergy's consolidated financial statements also include its other principal subsidiaries: FENOC, FES and its subsidiary FGCO, FESC, ~~FirstCom,~~ FSG, ~~GPU Capital, GPU Power, MARBEL~~ and MYR. ~~The Companies~~

FirstEnergy and its subsidiaries follow GAAP and comply with the ~~accounting~~regulations, orders, policies and practices prescribed by the SEC, FERC and, as applicable, PUCO, PPUC ~~NJBPU~~ and FERC. The condensed 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 prior year amounts have been reclassified to conform with the current year presentation. In particular, expenses (including transmission and congestion charges) were reclassified among purchased power, other operating costs and depreciation and amortization to conform with the current year presentation of generation commodity costs. In addition, revenues, expenses and taxes related to certain divestitures in 2003 have been reclassified and reported net in discontinued operations (see Note 2). 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, 2003 for FirstEnergy and the Companies.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 ~~those~~these estimates. The reported results of operations are not indicative of results of operations for any future period. ~~FirstEnergy's~~

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' independent accountants have performed reviews of, and issued reports on, these~~Companies. The consolidated ~~interim~~unaudited financial statements of FirstEnergy and each of the Companies reflect all normal recurring adjustments that, in ~~accordance~~the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain businesses divested in the first quarter of 2005 have been classified as discontinued operations on the Consolidated Statements of Income (see Note 6). As discussed in Note 15, interim period segment reporting in 2004 was reclassified to conform with ~~standards established by~~ the American Institute of Certified Public Accountants. 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 7current year business segment organizations and ~~11 of that Act, and the independent accountant's liability under Section 11 does not extend to them. 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: Consolidation~~ 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 and VIE's for which FirstEnergy or any of its subsidiaries is the primary beneficiary.~~interest. Intercompany transactions and balances are eliminated in consolidation. Investments in nonconsolidated affiliates (20-50 percent owned companies, joint ventures and partnerships) over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control, are accounted for onunder the equity ~~basis. 1~~ ~~FIN 46R addresses the consolidation of VIEs, including SPEs, that are not controlled through voting interests or in which~~method. Under the equity ~~investors do~~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 ~~bear~~be considered a report within the ~~residual economic~~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 its BGS obligation in New Jersey and 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 or energy sale. 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.~~ rewards of ownership transferred with each transaction.FES has accounted for these transactions on a gross basis in accordance with EITF 99-19.

The ~~first step~~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 EITF is expected to address under ~~FIN 46R is to determine whether an entity is~~what circumstances two or more transactions with the same counterparty should be viewed as a single nonmonetary transaction within the scope of ~~FIN 46R which occurs if it is deemed~~APB 29. If the EITF were to determine that transactions such as FES' purchases and sales in the PJM Market should be ~~a VIE. FirstEnergy and its subsidiaries consolidate those VIEs~~accounted for ~~which they have determined that they are~~as nonmonetary transactions, FES would report the ~~primary beneficiary as defined by FIN 46R. The provisions of FIN 46R were effective immediately for~~ transactions ~~entered into subsequent~~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 $280 million for the first quarter of 2004.

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 a $5.9 million increase (CEI - $2.1 million, OE - $3.3 million, Penn - - $0.1 million, TE - $0.5 million, FGCO - $(0.1) million) in income before discontinued operations and net income ($0.02 per share of common stock) during the first quarter of 2005.

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 0.5 million in the three months ended March 31, ~~2003~~2005 and ~~became effective no later than December 31, 2003 for entities that were considered SPEs under previous guidance, and no later than~~3.3 million in the three months ended March 31, 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. The following table reconciles the denominators for basic and diluted earnings per share from Income Before Discontinued Operations:

Reconciliation of Basic and	Three Months Ended
Diluted Earnings per Share	March 31,
	2005		2004
	*(In thousands)*

Income Before Discontinued Operations	$	140,788	$	172,526

Average Shares of Common Stock Outstanding:
Denominator for basic earnings per share
(weighted average shares outstanding)		327,908		327,057

Assumed exercise of dilutive stock options and awards		1,519		1,977

Denominator for diluted earnings per share		329,427		329,034

Income Before Discontinued Operations per common share:
Basic	$	0.43	$	0.53
Diluted	$	0.42	$	0.53

5. - GOODWILL

FirstEnergy's goodwill primarily relates to its regulated services segment. In the three months ended March 31, 2005, FirstEnergy adjusted goodwill related to the divestiture of non-core operations (FES' natural gas business, the 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 13) 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 ended March 31, 2005 is shown below.

	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		(12	)		--		--		--			--			--
Adjustments related to GPU acquisition		(4	)		--		--		(1	)		(2	)		(1	)
Balance as of March 31, 2005	$	6,034		$	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 will account for its remaining 31.85% interest in FirstCom on the equity basis.

In the first quarter of 2005, FirstEnergy sold its FSG subsidiaries, Elliott-Lewis and Spectrum, and MYR subsidiary, Power Piping Company, resulting in an after-tax gain of $12 million. FSG's remaining subsidiaries qualified as held for sale in accordance with SFAS 144 and are expected to be recognized as completed sales by the fourth quarter of 2005. The assets and liabilities of these remaining FSG subsidiaries are not material to FirstEnergy’s Consolidated Balance Sheet as of March 31, 2005 and have therefore not been separately classified as assets held for sale.

Net income (including the sales gains discussed above) for Elliott-Lewis, Power Piping and FES' natural gas business of $19 million for the first quarter of 2005 and $1 million for the first quarter of 2004 are reported as discontinued operations on FirstEnergy's Consolidated Statements of Income. Pre-tax operating results for these entities were $4 million for the first quarter of 2005 and $3 million for the first quarter of 2004. Revenues associated with discontinued operations for the first quarter of 2005 and 2004 were $191 million and $186 million, respectively. It is not certain that the remaining FSG businesses will meet the criteria for discontinued operations; therefore, the net loss ($2 million for the first quarter of 2005 and $1 million for the first quarter of 2004) from these subsidiaries has not been included in discontinued operations. See Note 15 for FSG's segment financial information.

	Three Months Ended
	March 31,
	2005		2004
	*(In millions)*
Discontinued Operations (Net of tax)
Gain on sale:
Natural gas business	$	5	$	--
Elliot-Lewis, Spectrum and Power Piping		12		--
Reclassification of operating income		2		1
Total	$	19	$	1

7. - DERIVATIVE INSTRUMENTS

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. As of March 31, 2005, FirstEnergy had fixed-for-floating interest rate swap agreements with anaggregate notional amount of $1.75 billion. During the first quarter of 2005, FirstEnergy executed new interest rate swaps with a total notional amount of $100 million. Under these agreements, FirstEnergy receives fixed cash flows based on the fixed coupons of hedged securities and pays variable cash flows based on short-term variable market interest rates.The weighted average fixed interest rate of senior notes and subordinated debentures hedged by the swap agreements was 6.51%. The interest rate swaps have effectively converted that rate to a current, weighted average variable interest rate of 4.91%.Changes in the fair value of derivatives designated as fair value hedges and the corresponding changes in the fair value of the hedged risk attributable to a recognized asset, liability, or unrecognized firm commitment are recorded in earnings. Since the fair value hedges are effective, the amounts recorded will be offset in earnings.

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 net deferred loss of $87 million included in AOCL as of March 31, 2005, for derivative hedging activity, as compared to the December 31, 2004 balance of $92 million in net deferred losses, resulted from a $5 million reduction related to current hedging activity, a $4 million increase due to the sale of gas business contracts and a $4 million decrease due to net hedge losses included in earnings during the three months ended March 31, 2005. Approximately $10 million (after tax) of the net deferred loss on derivative instruments in AOCL as of March 31, 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.

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 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 a revision to SFAS 123 which requires expensing the fair value of stock options (see Note 14). 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 ~~entities. See Variable Interest Entities below. Variable Interest Entities~~ companies with a fiscal year beginning January 1. 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 to stock-based employee compensation in the current reporting periods.

	Three Months Ended
	March 31,
	2005			2004
	*(In thousands)*

Net income, as reported	$	159,726		$	173,999

Add back compensation expense
reported in net income, net of tax
(based on APB 25)*		7,969			6,694

Deduct compensation expense based
upon estimated fair value, net of tax		(11,026	)		(11,098	)

Pro forma net income	$	156,669		$	169,595

Earnings Per Share of Common Stock -
Basic
As Reported	$	0.49		$	0.53
Pro Forma	$	0.48		$	0.52
Diluted
As Reported	$	0.48		$	0.53
Pro Forma	$	0.48		$	0.52

*Includes restricted stock, stock options, performance shares, Employee Stock Ownership Plan,

Executive Deferred Compensation Plan and Deferred Compensation Plan for Outside Directors.

FirstEnergy has reduced its use of stock options and increased its use of performance-based, restricted stock units. Therefore, the pro forma effects of applying SFAS 123 may not be representative of its future effect. FirstEnergy has not and does not expect to accelerate out-of-the-money options in anticipation of implementing SFAS 123(R) on January 1, 2006 (see Note 14 - "New Accounting Standards and Interpretations").

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 $1.095 billion as of March 31, 2005 included $1.071 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 March 31, 2005, the fair value of the decommissioning trust assets was $1.604 billion.

The following tables provide the beginning and ending aggregate carrying amount of the ARO and the changes to the balance during the three months ended March 31, 2005 and 2004, respectively.

	FirstEnergy		OE		CEI		TE		Penn		JCP&L		Met-Ed		Penelec
ARO Reconciliation	*(In millions)*

Balance, January 1, 2005	$	1,078	$	201	$	272	$	194	$	138	$	73	$	133	$	66
Liabilities incurred		--		--		--		--		--		--		--		--
Liabilities settled		--		--		--		--		--		--		--		--
Accretion		17		3		4		3		2		2		2		1
Revisions in estimated cash flows		--		--		--		--		--		--		--		--
Balance, March 31, 2005	$	1,095	$	204	$	276	$	197	$	140	$	75	$	135	$	67


Balance, January 1, 2004	$	1,179	$	188	$	255	$	182	$	130	$	110	$	210	$	105
Liabilities incurred		--		--		--		--		--		--		--		--
Liabilities settled		--		--		--		--		--		--		--		--
Accretion		19		3		4		3		2		1		3		2
Revisions in estimated cash flows		--		--		--		--		--		--		--		--
Balance, March 31, 2004	$	1,198	$	191	$	259	$	185	$	132	$	111	$	213	$	107

10. - PENSION AND OTHER POSTRETIREMENT BENEFITS:

The components of FirstEnergy's net periodic pension cost and other postretirement benefit cost (including amounts capitalized) as of March 31, 2005 and 2004, consisted of the following:

	Pension Benefits						Other Postretirement Benefits
	2005			2004			2005			2004
				*(In millions)*

Service cost	$	19		$	19		$	10		$	11
Interest cost		64			63			28			33
Expected return on plan assets		(86	)		(71	)		(11	)		(13	)
Amortization of prior service cost		2			2			(11	)		(12	)
Recognized net actuarial loss		9			10			10			11
Net periodic cost	$	8		$	23		$	26		$	30

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 months ended March 31, 2005 and 2004 were as follows:

	Pension Benefit Cost (Credit)					Other Postretirement Benefit Cost
	2005			2004		2005		2004
				*(In millions)*

OE	$	0.2		$	1.7	$	5.8	$	7.1
Penn		(0.2	)		0.1		1.2		1.5
CEI		0.3			1.6		3.8		5.6
TE		0.3			0.8		2.2		2.0
JCP&L		(0.2	)		1.9		2.7		1.6
Met-Ed		(1.1	)		0.1		0.4		1.3
Penelec		(1.3	)		0.1		1.9		1.4

11. - VARIABLE INTEREST ENTITIES

Leases

Included in ~~FirstEnergy's~~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~~OE’s 1987 sale and leaseback ~~transactions involving~~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. Consolidation of PNBV by FirstEnergy and OE as of December 31, 2003 changed the trust investment of $361 million to an investment in collateralized lease bonds of $372 million. The $11 million increase represented the minority interest in the total assets of PNBV. Shippingport was established to purchase all of the lease obligation bonds issued ~~by the owner trusts~~ in ~~CEI's~~connection with CEI’s and ~~TE's~~TE’s Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE ~~acquired all of~~used debt and available funds to purchase the notes issued by Shippingport. Consolidation of this entity had no impact on the financial statements of FirstEnergy. Prior to the adoption of FIN 46R, the assets and liabilities of Shippingport were included on a proportionate basis in the financial statements of CEI and TE. Adoption of FIN 46R resulted in the consolidation of Shippingport by CEI as of December 31, 2003. Shippingport's note payable to TE of $199 million ($10 million current) and $208 million ($9 million current) as of March 31, 2004 and December 31, 2003, respectively, is included in long-term debt on CEI's Consolidated Balance Sheets. Through its investment in PNBV, OE has, and through their investments in Shippingport, CEI and TE have, variable interests in certain owner trusts that acquired the interests in the Perry Plant and Beaver Valley Unit 2, in the case of OE, and the Bruce Mansfield Plant, in the case of CEI and TE. FirstEnergy concluded that OE, CEI and TE were not the primary beneficiaries of the relevant owner trusts and were therefore not required to consolidate these entities. The leases are accounted for as operating leases in accordance with GAAP. The combined purchase price of $3.1 billion for all of the interests acquired by the owner trusts in 1987 was funded with debt of $2.5 billion and equity of $600 million. Each of

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 ~~$706~~$688 million, ~~$109~~$99 million and ~~$595~~$566 million, respectively, that would not be payable if the casualty value payments are made. As of March 31, 2004, CEI and TE have recorded above-market lease obligations related to the Bruce Mansfield Plant and Beaver Valley Unit 2 totaling $1.1 billion (CEI - $774 million and TE - $311 million), of which $85 million (CEI - $60 million and TE - $25 million) is current. CEI formed a wholly owned statutory business trust to sell preferred securities and invest the gross proceeds in 9% subordinated debentures of CEI. The sole assets of the trust are the subordinated debentures

Power Purchase Agreements

In accordance with an aggregate principal amount of $103 million. The trust's preferred securities are redeemable at 100% of their principal amount at CEI's option beginning in December 2006. CEI has effectively provided a full and unconditional guarantee of the trust's obligations under the preferred securities. Met-Ed and Penelec each formed statutory business trusts for substantially similar transactions to those of CEI. However, ownership of the respective Met-Ed and Penelec trusts is through separate wholly owned limited partnerships. The sole assets of each trust are the preferred securities of the applicable limited partnership, whose sole assets are the 7.35% and 7.34% subordinated debentures (aggregate principal amount of $103 million each) of Met-Ed and Penelec, respectively. The trust's preferred securities are redeemable at 100% of their principal amount at the option of Met-Ed and Penelec beginning in May 2004 and September 2004, respectively. In each case, Met-Ed and Penelec have effectively provided a full and unconditional guarantee of obligations under the trust's preferred securities. Met-Ed has provided notice to holders of the trust preferred securities that it intends to redeem such securities in May 2004. 2 ~~Upon adoption of~~ FIN 46R, the limited partnerships and statutory business trusts discussed above were no longer consolidated on the financial statements of FirstEnergy or, as applicable, CEI, Met-Ed or Penelec. As of December 31, 2003 and March 31, 2004, subordinated debentures held by the affiliated trusts were included in long-term debt of the applicable company and equity investments in the trusts were included in other investments. For the quarter ended March 31, 2004, FirstEnergy evaluated ~~among other entities,~~ 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 ~~an EUOC~~the Companies and the contract price for power is correlated with the ~~plant's~~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, ~~either~~neither JCP&L, Met-Ed ornor Penelec ~~do not~~ 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 ~~has requested but not received~~periodically requests from these nine entities the information necessary to determine whether ~~these nine entities~~they are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. ~~In most cases,~~FirstEnergy has been unable to obtain the requested information, which in most cases was deemed by the requested entity to be ~~competitive and proprietary data.~~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 first quarters of 2005 and 2004 and 2003 were $51 million (JCP&L - $28 million, Met-Ed - $16 million and Penelec - $7 million) and $56 million (JCP&L - $34 million, Met-Ed - $15 million and Penelec - $7 million), respectively. FirstEnergy is required to continue to make exhaustive efforts to obtain the necessary information in future periods and is unable to determine the possible impact of consolidating any such entity without this information. Earnings Per Share Basic earnings per share are computed using the weighted average of actual common shares outstanding as the denominator. Diluted earnings per share reflect the weighted average of actual common shares outstanding plus the potential additional common shares that could result if dilutive securities and agreements were exercisedshown in the denominator. In the first quarter of 2004 and 2003, stock-based awards to purchase shares of common stock totaling 3.3 million and 3.6 million, respectively, 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. The following table reconciles the denominators for basic and diluted earnings per share from Income before Discontinued Operations and Cumulative Effect of Accounting Change: Three Months Ended March 31, Reconciliation of Basic and -------------------- Diluted Earnings per Share 2004 2003 --------------------------------------------------------------------------- (In thousands) Income before discontinued operations and cumulative effect of accounting change............ $173,999 $114,380 Average Shares of Common Stock Outstanding: Denominator for basic earnings per share (weighted average shares actually outstanding)... 327,057 293,886 Assumed exercise of dilutive stock options and awards....................................... 1,977 991 Denominator for diluted earnings per share.......... 329,034 294,877 =========================================================================== Income before Discontinued Operations and Cumulative Effect of Accounting Change, per common share: Basic............................................. $0.53 $0.39 Diluted........................................... $0.53 $0.39 --------------------------------------------------------------------------- Preferred Stock Subject to Mandatory Redemption Long-term debt includes the preferred stock of consolidated subsidiaries subject to mandatory redemption as of March 31, 2004 and December 31, 2003 in accordance with SFAS 150. This standard, issued in May 2003, establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity; certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. The adoption of SFAS 150 effective July 1, 2003 had no impact on FirstEnergy's Consolidated Statements of Income because the preferred dividends were previously included in net interest charges and required no reclassification. CEI and Penn, however, did not include the 3 preferred dividends on their manditorily redeemable preferred stock in interest expense for the quarter ended March 31, 2003, but have included the dividends in interest charges for the quarter ended March 31, 2004. below:

	Three Months Ended
	March 31,
	2005		2004
	*(In millions)*
JCP&L	$	27	$	28
Met-Ed		16		16
Penelec		7		7
	$	50	$	51

Securitized Transition Bonds

The consolidated financial statements of FirstEnergy and JCP&L include the ~~financial statements~~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 ~~each of~~ FirstEnergy's and JCP&L's Consolidated Balance Sheets. The transition bonds ~~represent~~are obligations ~~only~~ 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. Derivative Accounting FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including electricity, natural gas and coal. 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 executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. FirstEnergy uses derivatives to hedge the risk of price and interest rate fluctuations. FirstEnergy's primary ongoing hedging activity involves cash flow hedges of electricity and natural gas purchases. The maximum periods over which the variability of electricity and natural gas cash flows are hedged are two and three years, respectively. Gains and losses from hedges of commodity price risks are included in net income when the underlying hedged commodities are delivered. Also, the ineffective portion of hedge gains and losses is included in net income. In 2001, FirstEnergy entered into interest rate derivative transactions to hedge a portion of the anticipated interest payments on debt related to the GPU acquisition. Gains and losses from hedges of anticipated interest payments on acquisition debt are included in net income over the periods that hedged interest payments are made - 5, 10 and 30 years. Gains and losses from derivative contracts are included in other operating expenses. The net deferred loss included in AOCL as of March 31, 2004 and December 31, 2003 was $111 million. Approximately $6 million (after tax) of the net deferred loss on derivative instruments in AOCL as of March 31, 2004, 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. During the first quarter of 2004, FirstEnergy executed fixed-for-floating interest rate swap agreements with an aggregate notional amount of $200 million, whereby FirstEnergy receives fixed cash flows based on the fixed coupons of the hedged securities and pays variable cash flows based on short-term variable market interest rates. 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 received, and interest payment dates match those of the underlying debt obligations. FirstEnergy entered into interest rate swap agreements on $200 million notional amount of its subsidiaries' senior notes and subordinated debentures having a weighted average fixed interest rate of 5.73%; the interest rate swap agreements have effectively converted that rate to a current weighted average variable rate of 2.33%. The notional values of interest rate swap agreements increased to $1.35 billion as of March 31, 2004 from $1.15 billion as of December 31, 2003. Goodwill In a business combination, the excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, FirstEnergy evaluates 4 its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If an impairment is indicated, FirstEnergy recognizes a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. As of March 31, 2004, FirstEnergy had $6.1 billion of goodwill that primarily relates to its regulated services segment. In the first quarter of 2004, FirstEnergy adjusted goodwill for interest received on a pre-merger income tax refund related to the former GPU companies. A summary of the changes in FirstEnergy's goodwill for the three months ended March 31, 2004 is shown below: (In millions) ------------------------------------------------------ Balance as of December 31, 2003 ........ $6,128 GPU acquisition......................... (11) ------ Balance as of March 31, 2004............ $6,117 ====== Comprehensive Income Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholders' equity, except those resulting from transactions with common stockholders. As of March 31, 2004, FirstEnergy's AOCL was approximately $344 million as compared to the December 31, 2003 balance of $353 million. A reconciliation of net income to comprehensive income for the three months ended March 31, 2004 and 2003, is shown below: Three Months Ended March 31, ------------------- 2004 2003 ---- ---- (In thousands) Net income............................. $173,999 $218,502 Other comprehensive income, net of tax: Change in fair value of hedge transactions (393) 4,341 Unrealized gains on available for sale securities 9,215 1,484 -------- -------- Comprehensive income................... $182,821 $224,327 ======== ======== Asset Retirement Obligations FirstEnergy recognizes a liability for retirement obligations associated with tangible assets in accordance with SFAS 143. The Companies recognize a regulatory asset or liability when the criteria for such treatment are met. FirstEnergy has identified applicable legal obligations as defined under the standard 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 was $1.198 billion as of March 31, 2004 and included $1.185 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 (as discussed in FASB Concepts No. 7) 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 March 31, 2004, the fair value of the decommissioning trust assets was $1.420 billion. Under the current terms of the plants' operating licenses, payments for decommissioning of the nuclear generating units would begin in 2014, when actual decommissioning work would begin. The following table provides the beginning and ending aggregate carrying amount of the total ARO and the changes to the balance during the first quarter of 2004. ARO Reconciliation 2004 ---------------------------------------------------------------------------- (In millions) Beginning balance as of January 1, 2004 ...................... $1,179 Liabilities incurred.......................................... -- Liabilities settled........................................... -- Accretion in 2004............................................. 19 Revisions in estimated cash flows............................. -- ------------------------------------------------------------------------ Ending balance as of March 31, 2004........................... $1,198 ------------------------------------------------------------------------ 5 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 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 March 2004, the FASB issued an exposure draft of a proposed standard that, if adopted, will change the accounting for employee stock options and other equity-based compensation. The proposed standard would require companies to expense the fair value of stock options on the grant date and would be effective for the Companies on January 1, 2005. FirstEnergy will evaluate the requirements of the final standard, expected by late 2004, to determine the impact on its results of operations. If FirstEnergy had accounted for employee stock options under the fair value method, as provided under SFAS 123, a higher value would have been assigned to the options granted. The effects of applying fair value accounting to FirstEnergy's stock options would be reductions to net income and earnings per share. The following table summarizes those effects. Three Months Ended March 31, ------------------ 2004 2003 ---- ---- (In thousands) Net income, as reported................... $173,999 $218,502 Add back stock-based compensation expense reported in net income, net of tax (based on APB 25)....................... -- 43 Deduct stock-based compensation expense based upon estimated fair value, net of tax (4,404) (2,983) --------------------------------------------------------------------- Adjusted net income....................... $169,595 $215,562 --------------------------------------------------------------------- Earnings Per Share of Common Stock - Basic As Reported.......................... $0.53 $0.74 Adjusted............................. $0.52 $0.73 Diluted As Reported.......................... $0.53 $0.74 Adjusted............................. $0.52 $0.73 Discontinued Operations FirstEnergy's discontinued operations in the first quarter of 2003 consisted of the net results aggregating $2 million from its Argentina and Bolivia international businesses and certain domestic operations divested in 2003. The related revenues, expenses and taxes were reclassified from the previously reported Consolidated Statement of Income for the quarter ended March 31, 2003 and netted in Discontinued Operations. In April 2003, FirstEnergy divested its ownership in Emdersa through the abandonment of its shares in Emdersa's parent company, GPU Argentina Holdings, Inc. The abandonment was accomplished by relinquishing FirstEnergy's shares to the independent Board of Directors of GPU Argentina Holdings, relieving FirstEnergy of all rights and obligations relative to this business. FirstEnergy sold its Bolivia operations, Empresa Guaracachi S.A., in December 2003. Domestic operations sold in 2003 consisted of three former FSG subsidiaries and the MARBEL subsidiary, NEO. Cumulative Effect of Accounting Change As a result of adopting SFAS 143 in January 2003, asset retirement costs were recorded in the amount of $602 million as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $415 million. The ARO liability on the date of adoption was $1.11 billion, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. The remaining cumulative effect adjustment for unrecognized depreciation and accretion, offset by the reduction in the existing decommissioning liabilities and the reversal of accumulated estimated removal costs for non-regulated generation assets, was a $175 million increase to income, $102 million net of tax, or $0.35 per share of common stock (basic and diluted) in the quarter ended March 31, 2003. 6 Restatements of TE and JCP&L Previously Reported Quarterly Results Earnings for the first quarter of 2003 have been restated for TE and JCP&L to reflect adjustments to costs that were subsequently capitalized to construction projects. The results for TE have also been restated to correct the amount reported for interest expense. TE's costs which were originally recorded as operating expenses and were subsequently capitalized to construction were $0.4 million ($0.2 million after-tax) in the first quarter of 2003. TE's interest expense was overstated by $0.9 million ($0.5 million after-tax) in the first quarter of 2003. Similar to TE, JCP&L's capital costs originally recorded as operating expenses were $0.2 million ($0.1 million after-tax) in the first quarter of 2003. The impact of these adjustments was not material to the consolidated balance sheets or consolidated statements of cash flows for TE and JCP&L for any quarter of 2003. The effects of these adjustments on the consolidated statements of income previously reported for TE and JCP&L for the three months ended March 31, 2003, are as follows:

12. - COMMITMENTS, GUARANTEES AND CONTINGENCIES: Capital Expenditures FirstEnergy's current forecast reflects expenditures of approximately $2.3 billion (OE-$295 million, CEI-$275 million, TE-$141 million, Penn-$143 million, JCP&L-$446 million, Met-Ed-$168 million, Penelec-$198 million, ATSI-$66 million, FES-$443 million and other subsidiaries-$125 million) for property additions and improvements from 2004-2006, of which approximately $720 million (OE-$111 million, CEI-$95 million, TE-$49 million, Penn-$63 million, JCP&L-$150 million, Met-Ed-$55 million, Penelec-$65 million, ATSI-$23 million, FES-$71 million and other subsidiaries-$38 million) is applicable to 2004. Investments for additional nuclear fuel during the 2004-2006 period are estimated to be approximately $315 million (OE-$45 million, CEI-$62 million, TE-$44 million, Penn-$35 million and FES-$129 million), of which approximately $86 million (OE-$26 million, CEI-$27 million, TE-$12 million and Penn-$21 million) applies to 2004. Guarantees and Other Assurances

(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 March 31, ~~2004,~~2005, outstanding guarantees and other assurances aggregated ~~$1.9~~approximately $2.4 billion and included contract guarantees ($11.0 billion), surety bonds ($~~0.2~~0.3 billion) and ~~letters of credit~~LOC ($~~.7 million)~~1.1 billion).

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy ~~marketing~~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 ~~and its subsidiaries~~ to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $1$0.9 billion (included in the ~~$1.9~~$1.0 billion discussed above) as of March 31, ~~2004~~2005 will increase amounts otherwise to be paid by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related ~~activities is remote.~~ 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~~rating-downgrade or ~~"material~~“material adverse ~~event"~~event” the immediate ~~payment~~posting of cash collateral or provision of an LOC may be ~~required.~~required of the subsidiary. The following table summarizes collateral provisions in effect as of March 31, 2004: Collateral Paid Total -------------------------- Remaining Collateral Provisions Exposure Cash Letters of Credit Exposure(1) - -------------------------------------------------------------------------------- (In millions) Rating downgrade.......... $228 $133 $18 $ 77 Adverse event............. 232 -- 69 163 - ---------------------------------------------------------------------------- Total..................... $460 $133 $87 $240 ============================================================================ (1) As of April 12, 2004, FirstEnergy's remaining exposure was $237 million, with $141 million of cash and $72 million of letters of credit provided as collateral. 2005:

			Collateral Paid				Remaining
Collateral Provisions	Exposure		Cash		LOC		Exposure⁽¹⁾
	*(In millions)*
Credit rating downgrade	$	364	$	153	$	18	$	193
Adverse Event		42		--		8		34
Total	$	406	$	153	$	26	$	227

⁽¹⁾	As of May 2, 2005, FirstEnergy’s total exposure decreased to $357 million and the remaining exposure decreased to $183 million - net of $148 million of cash collateral and $26 million of LOC collateral provided by counterparties.

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of ~~$240~~$267 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.

FirstEnergy has ~~also~~ guaranteed the obligations of the operators of the TEBSA project, ~~in Colombia,~~ 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 ~~the TEBSA project lenders a $60 million letter of credit,~~an LOC (currently at $47 million), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA. ~~This letter of credit granted FirstEnergy the ability to sell its remaining 20.1% interest in Avon (parent of Midlands Electricity in the United Kingdom). Environmental Matters~~

(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 ~~material~~ compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately ~~$91~~$430 million for ~~2004~~2005 through ~~2006, which~~2007.

The Companies accrue environmental liabilities only when they conclude that it is ~~included~~probable that they have an obligation for such costs and can reasonably determine the amount of such costs. Unasserted claims are reflected in the ~~$2.3 billion~~Companies’ determination of ~~forecasted capital expenditures for 2004 through 2006. Additional estimated capital expenditures of $481 million relating to proposed~~ environmental ~~laws could be required after 2006.~~ liabilities and are accrued in the period that they are both probable and reasonably estimable.

Clean Air Act Compliance

The Companies are required to meet federally approved ~~SO2~~SO₂ regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to ~~$31,500~~$32,500 for each day the unit is in violation. The EPA has an interim enforcement policy for ~~SO2~~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~~SO₂ reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. ~~NOx~~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 ~~NOx~~NO_x reductions from the Companies' facilities. The EPA's ~~NOx~~NO_x Transport Rule imposes uniform reductions of ~~NOx~~NO_x emissions (an approximate ~~85%~~85 percent reduction in utility plant ~~NOx~~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 ~~NOx~~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 ~~(SIP) must comply by May 31, 2004 with individual state NOx budgets. New Jersey~~through combustion controls and ~~Pennsylvania submitted a SIP that required compliance with the NOx budgets at the Companies' New Jersey~~post-combustion controls, including Selective Catalytic Reduction and Pennsylvania facilities by May 1, 2003. Michigan and Ohio submitted a SIP that requires compliance with the NOx budgets at the Companies' Michigan and Ohio facilities by May 31, 2004. The Companies' facilities have complied with the NOx budgets in 2003 and 2004, respectively. 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 ~~December 17, 2003,~~March 10, 2005, the EPA ~~proposed~~finalized the ~~"Interstate~~"Clean Air ~~Quality~~Interstate Rule" covering a total of 2928 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air ~~pollution~~ emissions from 2928 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. ~~The EPA has proposed the Interstate Air Quality Rule to "cap-and-trade" NOx~~CAIR will require additional reductions of NO_x and ~~SO2~~SO₂ emissions in two phases (Phase I in 2009 for NOx, 2010 for SO₂ and Phase II in ~~2015)~~2015 for both NOx and SO₂). The Companies’ Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to the caps on SO₂ and NOx 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~~SO₂ emissions ~~would~~will be reduced by ~~approximately 3.6 million tons in~~45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions ~~ultimately~~ reaching ~~more than 5.5~~73% (from 2003 levels) by 2015, capping SO₂ emissions in affected states to just 2.5 million tons annually. ~~NOx emission~~NO_x emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions ~~would measure about 1.5~~reaching 61% (from 2003 levels) by 2015, achieving a regional NO_x cap of 1.3 million tons ~~in 2010 and 1.8 million tons in 2015.~~annually. The future cost of compliance with these ~~proposed~~ regulations may be substantial and will depend on ~~whether and~~ how they are ultimately implemented by the states in which the Companies operate affected facilities.

Mercury Emissions

W. H. Sammis Plant

In 1999 and 2000, the EPA issued ~~Notices of Violation (NOV)~~NOV or a Compliance ~~Order~~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, which included 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 subject to a thirty-day public comment period that ended on April 29, 2005 and final approval by the District Court Judge, 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 ~~ruling concludes~~settlement agreement also requires OE and Penn to spend up to $25 million towards environmentally beneficial projects, which include wind energy purchase power agreements over a 20-year term. OE and Penn also agreed to pay a civil penalty of $8.5 million. Results for the ~~liability phase~~first quarter of 2005 include the penalties payable by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also accrued $9.2 million and $0.8 million, respectively, for 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 ~~case,~~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 ~~deals with applicability~~include low or non-CO₂ emitting gas-fired and nuclear generators.

Clean Water Act

Various water quality regulations, the majority of ~~Prevention~~which are the result of ~~Significant Deterioration provisions~~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 ~~Air Act.~~Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The ~~remedy phase,~~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 ~~is currently scheduled~~occurs when aquatic species are drawn into a facility's cooling water system. The Companies are conducting comprehensive demonstration studies, due in 2008, to ~~be ready for trial beginning July 19, 2004, will address civil penalties and what,~~determine the operational measures, equipment or restoration activities, if any, ~~actions should be taken to further reduce emissions at~~necessary for compliance by their facilities with the plant. In the ruling, the Court indicated that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact on FirstEnergy's financial condition and results of operations. Managementperformance standards. FirstEnergy is unable to predict the ~~ultimate~~ outcome of ~~this matter and no liability has been accrued as~~such studies. Depending on the outcome of ~~March 31, 2004.~~ 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 ~~be held~~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 March 31, ~~2004,~~2005, based on estimates of the total 9 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 $65 million (JCP&L - ~~- $45.5~~$46.8 million, CEI - ~~$2.4~~$2.3 million, TE - $0.2 million, Met-Ed - ~~$0.05 million, Penelec - $0.02 million,~~$48,000 and other - ~~$16.8~~$15.2 million) as of March 31, 2004. The Companies accrue environmental liabilities only when they can 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. 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 U.S. 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% 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 includes 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. 2005.

(C)OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation

In July 1999, the Mid-Atlantic ~~states~~States experienced a severe heat ~~storm~~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~~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. Since July 1999, this litigation has involved a substantial amount of legal discovery including interrogatories, request for production of documents, preservation and inspection of evidence, and depositions of the named plaintiffs and many JCP&L employees. In addition, there have been many motions filed and argued by the parties involving issues such as the primary jurisdiction and findings of the NJBPU, consumer fraud by JCP&L, strict product liability, class decertification, and the damages claimed by the plaintiffs. In January 2000, the NJ Appellate Division determined that the trial court has proper jurisdiction over this litigation.

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 ~~products~~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 ~~have been~~were appealed to the ~~Appellation Division~~Appellate Division. The Appellate Court 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 transformers in Red Bank, New Jersey. On September 8, 2004, the New Jersey Supreme Court denied the motions filed by plaintiffs and ~~oral argument is scheduled~~JCP&L for ~~May 2004.~~leave to appeal the decision of the Appellate Court. 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 March 31, ~~2004.~~ 2005.

On August 14, 2003, various states and parts of southern Canada experienced a widespread power ~~outage. That outage~~outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. ~~On April 5, 2004, the~~The U.S. - ~~-Canada~~Canada Power System Outage Task ~~Force released its~~Force’s final report in April 2004 on ~~this outage. The final report supercedes~~ the ~~interim report that had been issued in November, 2003. In the final report, the Task Force~~outages concluded, among other things, that the problems leading to the ~~outage~~outages began in ~~FirstEnergy's~~FirstEnergy’s Ohio service area.Specifically, the final report concludes, among other things, that the initiation of the August ~~14th~~14, 2003 power ~~outage~~outages resulted from ~~the coincidence on that afternoon of several events, including,~~ 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~~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 10 effective real-time diagnostic support. The final report is publicly available through the Department of ~~Energy's~~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 ~~14th~~14, 2003 power ~~outage~~outages and that it does not adequately address the underlying causes of the ~~outage.~~outages. FirstEnergy remains convinced that the ~~outage~~outages cannot be explained by events on any one utility's system. The final report ~~contains~~contained 46 ~~"recommendations~~“recommendations to prevent or minimize the scope of future blackouts."” Forty-five of those recommendations ~~relate~~related to broad industry or policy matters while one, ~~relates~~including subparts, related to activities the Task Force ~~recommends~~recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and ~~ECAR.~~other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy ~~has undertaken~~implemented several initiatives, ~~some~~both prior to and ~~some~~ since the August ~~14th~~14, 2003 power ~~outage, to enhance reliability~~outages, which ~~are~~were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and ~~believes it will complete those relating to summer 2004 by June 30 (see Regulatory Matters below).~~collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these initiatives already were in process, ~~and budgeted in 2004,~~ FirstEnergy does not believe that any incremental expenses associated with additional initiatives ~~undertaken during~~completed in 2004 ~~will have~~had a material effect on its continuing operations or financial results. FirstEnergy notes, however, that the 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. FirstEnergy has not accrued a liability as of March 31, ~~2004~~2005 for any expenditures in excess of those actually incurred through that date. ~~Davis-Besse~~

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. One case was refiled on January 12, 2004 at the PUCO. The other two cases were appealed. One case was dismissed and no further appeal was sought. In the remaining case, the Court of Appeals on March 31, 2005 affirmed the trial court’s decision dismissing the case. It is not yet known whether further appeal will be sought. In addition to the one case that was 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 ~~plant.~~Nuclear Power Station. On December 10, 2004, FirstEnergy received a letter from the United States Attorney's Office stating that FENOC is ~~unable~~a target of the federal grand jury investigation into alleged false statements made to ~~predict the outcome of this investigation. In addition, FENOC remains subject to possible civil enforcement action by~~ the NRC in ~~connection with~~ the ~~events leading~~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 ~~Davis-Besse outage in 2002. Further, a petition was filed with~~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 April 21, 2005, the NRC ~~on March 29, 2004 by~~issued a ~~group objecting~~NOV and proposed a $5.45 million civil penalty related to the ~~NRC's restart order~~degradation of the Davis-Besse ~~Nuclear Power Station. The Petition seeks among other things, suspension~~reactor vessel head described above. Under the NRC’s letter, FENOC has ninety days to respond to this NOV. FirstEnergy accrued the remaining liability for the proposed fine of $3.45 million during the ~~Davis-Besse operating license.~~first quarter of 2005.

If it were ultimately determined that FirstEnergy or its subsidiaries has legal liability ~~or is otherwise made subject to enforcement action~~ based on ~~any of the above matters with respect to~~ the Davis-Besse ~~outage,~~head degradation, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.

Other Legal Matters ~~Various~~

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

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 ~~connection with, among other things,~~September 2003 relating to the restatements in August 2003 ~~by FirstEnergy and its Ohio utility subsidiaries~~ of previously reported results ~~the August 14th power outage described above,~~by FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, athave become the ~~Davis-Besse Nuclear Power Station. Depending upon the particular proceeding, the~~subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised ~~include alleged violations~~during the SEC's examination of ~~federal securities laws, breaches of fiduciary duties under state law by~~ FirstEnergy directors and officers, and damages as a result of one or more of the noted events. The securities cases have been consolidated into one action pending in federal court in Akron, Ohio. The derivative actions filed in federal court likewise have been consolidated as a separate matter, also in federal court in Akron. There also are pending derivative actions in state court. FirstEnergy's Ohio utility subsidiaries were also named as respondents in two regulatory proceedings initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14th power outage. 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 them. 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 outage. All three cases were dismissed for lack of jurisdiction. One case was refiled at the PUCO and the ~~other two have been appealed.~~ 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 second 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 ~~FirstEnergy~~it were ultimately determined tothat FirstEnergy or its subsidiaries have legal liability ~~in connection with~~or are otherwise made subject to liability based on the ~~legal proceedings described~~ above matter, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations. 11 4

13. - ~~PENSION AND OTHER POSTRETIREMENT BENEFITS: The components of net periodic pension and postretirement benefit cost consisted of the following:~~
Pension Benefits Other Benefits -------------------- ------------------ Three months ended Three months ended March 31, March 31, -------------------- ------------------ 2004 2003 2004 2003 - ------------------------------------------------------------------------------------------ (In millions) Service cost ............................. $ 19 $ 17 $ 10 $ 11 Interest cost............................. 63 64 30 35 Expected return on plan assets............ (71) (63) (11) (11) Transition obligation..................... -- -- -- 2 Amortization of prior service cost........ 2 2 (9) (2) Recognized net actuarial loss............. 10 16 10 11 ------ ------ ------ ------ Net periodic cost......................... $ 23 $ 36 $ 30 $ 46 ====== ====== ====== ======
FirstEnergy contributed $16 million to its other postretirement benefit plans in the first quarter of 2004 and has no funding requirements for the remainder of 2004. FirstEnergy did not contribute to its pension plans during the first quarter of 2004 and has no funding requirements for the remainder of 2004. The net periodic pension cost in the three months ended March 31, 2004 and March 31, 2003 included $3 million and $5 million, respectively, of costs capitalized. Similarly, the net periodic cost for other postretirement costs in the three months ended March 31, 2004 and March 31, 2003 included $4 million and $5 million, respectively, of capital costs. Pursuant to FSP 106-1 issued January 12, 2004, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 because of a plan amendment during the quarter, which required remeasurement of the plan's obligations. Based on the guidance in proposed FSP 106-b issued in March 2004, FirstEnergy has calculated a reduction of $318 million in the accumulated postretirement benefit obligation as a result of the federal subsidy provided under the Medicare Act. The subsidy reduced net periodic costs during the first quarter of 2004 by $10 million, which included increased amortization of the actuarial experience loss of $0.8 million, reduction of $6.1 million in past service cost, $1.1 million of current period service cost and $3.6 million of interest cost. Specific authoritative guidance on the accounting for the federal subsidy is pending, and when issued, could require a change to previously reported information. REGULATORY MATTERS:

Reliability Initiatives

In addition, the plan amendment announced in the first quarter of 2004 reduced postretirement benefit costs during the quarter by $9.2 million as a result of increased cost-sharing by employees and retirees effective January 1, 2005. 5 - INTERNATIONAL DIVESTITURES: FirstEnergy completed the sale of its international assets during the quarter ended March 31, 2004 with the sales of its remaining 20.1 percent interest in Avon on January 16, 2004, and its 28.67 percent interest in TEBSA on January 30, 2004. Impairment charges related to Avon and TEBSA were recorded in the fourth quarter oflate 2003 and ~~no gain or loss was recognized upon the sales in 2004. Avon, TEBSA~~early 2004, a series of letters, reports and other international assets sold in 2003 were acquired as part of FirstEnergy's November 2001 merger with GPU. 6 - REGULATORY MATTERS: In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry deregulation contain similar provisions which are reflected in the Companies' respective state regulatory plans: o allowing the Companies' electric customers to select their generation suppliers; o establishing PLR obligations to customers in the Companies' service areas; o allowing recovery of transition costs (sometimes referred to as stranded investment); o itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and transition costs recovery charges; o deregulating the Companies' electric generation businesses; o continuing regulation of the Companies' transmission and distribution system; and o requiring corporate separation of regulated and unregulated business activities. 12 Reliability Initiatives On October 15, 2003, NERC issued a Near Term Action Plan that contained recommendations for all control areas and reliability coordinators with respect to enhancing system reliability. Approximately 20 of the recommendations were ~~directed at the FirstEnergy companies~~issued from various entities, including governmental, industry and ~~broadly focused on initiatives that are recommended for completion by summer 2004. These initiatives principally relate to changes in voltage criteria~~ad hoc reliability entities (PUCO, FERC, NERC and reactive resources management; operational preparedness and action plans; emergency response capabilities; and, preparedness and operating center training. FirstEnergy presented a detailed compliance plan to NERC, which NERC subsequently endorsed on May 7, 2004, and the various initiatives are expected to be completed no later than June 30, 2004. On February 26 and 27, 2004, certain FirstEnergy companies participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC to review control area operations throughout much of the United States during 2004, is an independent review to identify areas for improvement. The final audit report was completed on April 30, 2004. The report identified positive observations and included various recommendations for improvement. FirstEnergy is currently reviewing the audit results and recommendations and expects to implement those relating to summer 2004 by June 30. Based on its review thus far, FirstEnergy believes that none of the recommendations identify a need for any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that NERC 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. On March 1, 2004, certain FirstEnergy companies filed, in accordance with a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. - Canada Power System Outage Task ~~Force interim report. In particular, the filing addressed upgrades to FirstEnergy's control room computer hardware and software and~~Force) regarding enhancements to ~~the training of control room operators. The PUCO will review the plan before determining the next steps, if any, in the proceeding. On April 22,~~regional reliability. In 2004, FirstEnergy ~~filed with FERC~~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 results of the FERC-ordered independent study of part of Ohio's power grid. The study examined, among other things, the reliability of the transmission grid in critical points in the Northern Ohio area and the need, if any, for reactive power reinforcements duringvarious initiatives to be completed by June 30 or summer 2004, ~~and 2005.~~with minor exceptions noted by FirstEnergy, which exceptions are now essentially complete. FirstEnergy is ~~currently reviewing the results of that study and expects to complete~~proceeding with the implementation of the recommendations ~~relating~~that were to be completed subsequent to 2004 ~~by this summer. Based on its review thus~~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, ~~FirstEnergy believes that~~implementation of the ~~study does~~recommendations has not ~~recommend any incremental~~required, nor is expected to require, substantial investment in new, or material ~~investment or~~ upgrades, to existing equipment. 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. ~~With respect~~Finally, the PUCO is continuing to ~~each~~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.

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 September 2005. FirstEnergy ~~has requested and NERC has agreed~~is unable to ~~provide, a technical assistance team~~predict the outcome of ~~experts to provide ongoing guidance and assistance in implementing and confirming timely and successful completion. Ohio~~this proceeding.

In July 1999, Ohio's electric utility restructuring legislation, which allowed Ohio electric customers to select their generation suppliers beginning January 1, 2001, was signed into law. Among other things,November 2004, the legislation provided for a 5% reduction on the generation portion of residential customers' bills and the opportunity to recover transition costs, including regulatory assets, from January 1, 2001 through December 31, 2005 (market development period). The period for the recovery of regulatory assets only can be extended up to December 31, 2010. The recovery period extension is related to the customer shopping incentives recovery discussed below. The PUCO was authorized to determine the level of transition cost recovery, as well as the recovery period for the regulatory assets portion of those costs, in considering each Ohio electric utility's transition plan application. In July 2000, the PUCOPPUC approved ~~FirstEnergy's transition plan for OE, CEI and TE (Ohio Companies) as modified by~~ a settlement agreement ~~with major parties to the transition plan. The application of SFAS 71 to OE's generation business~~filed by Met-Ed, Penelec and the nonnuclear generation businesses of CEI and TE was discontinued with the issuance of the PUCO transition plan order, as described further below. Major provisions of the settlement agreement consisted of approval of recovery of generation-related transition costs as filed of $4.0 billion net of deferred income taxes (OE-$1.6 billion, CEI-$1.6 billion and TE-$0.8 billion) and transition costsPenn that addressed issues related to ~~regulatory assets as filed of $2.9 billion net of deferred income taxes (OE-$1.0 billion, CEI-$1.4 billion~~a PPUC investigation into Met-Ed's, Penelec's and TE-$0.5 billion), with recovery through no later than 2006 for OE, mid-2007 for TE and 2008 for CEI, except where a longer period of recovery is provided for in the settlement agreement. The generation-related transition costs include $1.4 billion, net of deferred income taxes, (OE-$1.0 billion, CEI-$0.2 billion and TE-$0.2 billion) of impaired generating assets recognized as regulatory assets as described further below, $2.4 billion, net of deferred income taxes, (OE-$1.2 billion, CEI-$0.4 billion and TE-$0.8 billion) of above market operating lease costs and $0.8 billion, net of deferred income taxes, (CEI-$0.5 billion and TE-$0.3 billion) of additional plant costs that were reflected on CEI's and TE's regulatory financial statements. 13 ~~Also as~~Penn's service reliability performance. As part of the settlement, ~~agreement, FirstEnergy gives preferred access over its subsidiaries~~Met-Ed, Penelec and Penn agreed to ~~nonaffiliated marketers, brokers~~enhance service reliability, ongoing periodic performance reporting and ~~aggregators~~communications with customers, and to ~~1,120 MW~~collectively maintain their current spending levels of ~~generation capacity~~at least $255 million annually on combined capital and operation and maintenance expenditures for transmission and distribution for the years 2005 through ~~2005 at established prices for sales~~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 Companies' retail customers. Customer prices are frozen through the five-year market development period, which runs through the end of 2005, except for certain limited statutory exceptions, including the 5% reduction referred to above. In February 2003,

On August 5, 2004, the Ohio Companies ~~were authorized increases in annual revenues aggregating approximately $50 million (OE-$41 million, CEI-$4 million~~accepted the Rate Stabilization Plan as modified and TE-$5 million) to recover their higher tax costs resulting from the Ohio deregulation legislation. FirstEnergy's Ohio customers choosing alternative suppliers receive an additional incentive applied to the shopping credit (generation component) of 45% for residential customers, 30% for commercial customers and 15% for industrial customers. The amount of the incentive is deferred for future recovery from customers. Subject to approvalapproved by the PUCO ~~recovery will be accomplished~~on August 4, 2004, subject to a competitive bid process. The Rate Stabilization Plan was filed by ~~extending the respective transition cost recovery period. On October 21, 2003,~~ the Ohio ~~EUOC filed an application with the PUCO~~Companies to establish generation service rates beginning January 1, 2006, in response to ~~expressed~~PUCO concerns ~~by the PUCO~~ 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 filing included two options: o A competitive auction, which would establish a price for generation that customers would be charged during the period covered by the auction, or o Arevised Rate Stabilization Plan ~~which would extend~~extends current generation prices through 2008, ensuring adequate generation supply at ~~stable~~stabilized prices, and ~~continuing~~continues the Ohio ~~EUOC's~~Companies' support of energy efficiency and economic development efforts. ~~Under~~Other key components of the ~~first option,~~revised Rate Stabilization Plan include the following:

·	extension of the transition cost amortization period for OE from 2006 to as late as 2007; for CEI from 2008 to as late as mid-2009 and for TE from mid-2007 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 December 9, 2004, the PUCO rejected the auction price results from a required competitive bid process and issued an ~~auction would be conducted~~entry stating that the pricing under the approved revised 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 ~~service~~ for the ~~Ohio EUOC's customers. Beginning in 2006, customers~~years 2007 and 2008. Any acceptance of future competitive bid results would ~~pay market prices for generation as determined by the auction. Under~~terminate the Rate Stabilization Plan ~~option, customers would have price~~pricing, but not the related approved accounting, and supply stability through 2008 - three years beyond the end of the market development period - as well as the benefits of a competitive market. Customer benefits would include: customer savings by extending the current five percent discount on generation costs and other customer credits; maintaining current distribution base rates through 2007; market-based auctions that may be conducted annually to ensure that customers pay the lowest available prices; extension of the Ohio EUOC's support of energy-efficiency programs and the potential for continuing the program to give preferred access to nonaffiliated entities to generation capacity if shopping drops below 20%. Under the proposed plan, the Ohio EUOC are requesting: o Extension of the transition cost amortization period for OE from 2006 to 2007; for CEI from 2008 to mid-2009 and for TE from mid-2007 to mid-2008; o Deferral of interest costs on the accumulated shopping incentives and other cost deferrals as new regulatory assets; and o Ability to initiate a request to increase generation rates under certain limited conditions. On January 7, 2004,not until twelve months after the PUCO staff filed testimony on the proposed rate plan generally supporting the Rate Stabilization Plan as opposed to the competitive auction proposal. Hearings began on February 11, 2004. On February 23, 2004, after consideration of PUCO Staff comments and testimony as well as those provided by some of the intervening parties, FirstEnergy made certain modifications to the Rate Stabilization Plan. Oral arguments were held before the PUCO on April 21 and a decision is expected from the PUCO in the Spring of 2004. Transition Cost Amortization OE, CEI and TE amortize transition costs (see Regulatory Matters - Ohio) using the effective interest method. Under the Ohio transition plan, total transition cost amortization is expected to approximate the following for 2004 through 2009. (In millions) --------------------------------------- 2004...................... $794 2005...................... 922 2006...................... 371 2007...................... 208 2008...................... 164 2009...................... 46 --------------------------------------- 14 ~~The decrease in amortization beginning in 2006 results from the termination of generation-related transition cost recovery under the Ohio transition plan.~~ authorizes such termination.

New Jersey JCP&L's 2001 Final Decision and Order (Final Order) with respect to its rate unbundling, stranded cost and restructuring filings confirmed rate reductions set forth in its 1999 Summary Order, which had been in effect at increasing levels through July 2003. The Final Order also confirmed the establishment of a non-bypassable SBC to recover costs which include nuclear plant decommissioning and manufactured gas plant remediation, as well as a non-bypassable MTC primarily to recover stranded costs. The NJBPU has deferred making a final determination of the net proceeds and stranded costs related to prior generating asset divestitures until JCP&L's request for an IRS ruling regarding the treatment of associated federal income tax benefits is acted upon. Should the IRS ruling support the return of the tax benefits to customers, there would be no effect to FirstEnergy's or JCP&L's net income since the contingency existed prior to the merger and there would be an adjustment to goodwill. In addition, the Final Order provided for the ability to securitize stranded costs associated with the divested Oyster Creek Nuclear Generating Station. Under NJBPU authorization in 2002, JCP&L issued through its wholly owned subsidiary, JCP&L Transition, $320 million of transition bonds (recognized on the Consolidated Balance Sheet) which securitized the recovery of these costs and which provided for a usage-based non-bypassable TBC and for the transfer of the bondable transition property to another entity. Prior to August 1, 2003, JCP&L's PLR obligation to provide BGS to non-shopping customers was supplied almost entirely from contracted and open market purchases.

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 March 31, ~~2004,~~2005, the accumulated deferred cost balance totaled approximately ~~$425 million, after the charge discussed below. The NJBPU also allowed~~$472 million. New Jersey law allows for securitization of JCP&L's deferred balance ~~to the extent permitted by law~~ 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. There can be no assurance as to the extent, if any, that the NJBPU will permit such securitization. Under New Jersey transition legislation, all electric distribution companies were required to file rate cases to determine the level of unbundled rate components to become effective August 1, 2003.

The July 2003 NJBPU decision on JCP&L's two August 2002 rate filings requested increases in base electric rates of approximately $98 million annually and requested the recovery of deferred costs that exceeded amounts being recovered under the current MTC and SBC rates; one proposed method of recovery of these costs is the securitization of the deferred balance. This securitization methodology is similar to the Oyster Creek securitization discussed above. On July 25, 2003, the NJBPU announced its JCP&L base electric rate proceeding disallowed certain regulatory assets. JCP&L recorded charges to net income in 2003 for the disallowed costs aggregating $185 million ($109 net of tax). The subsequent NJBPU final decision ~~which reduced~~and order issued in May 2004 resulted in JCP~~&L's annual revenues by approximately $62~~&L recording a $5.4 million ~~effective August 1,~~reduction in 2004 of the estimated charges in 2003. The 2003 NJBPU decision also provided for an interim return on equity of 9.5% on JCP&L's rate ~~base for six to twelve months. During that period, JCP&L will initiate another~~base. The decision ordered a Phase II proceeding to ~~request recovery~~review whether JCP&L is in compliance with current service reliability and quality standards. The NJBPU also ordered that any expenditures and projects undertaken by JCP&L to increase its system's reliability be reviewed as part of ~~additional costs incurred~~the Phase II proceeding, to ~~enhance system reliability.~~determine their prudence and reasonableness for rate recovery. In that Phase II proceeding, the NJBPU could increase ~~the~~JCP&L’s return on equity to 9.75% or decrease it to 9.25%, depending on its assessment of the reliability of JCP&L's service. Any reduction would be retroactive to August 1, 2003. The net revenue decrease from the NJBPU's decision consists of a $223 million decrease in the electricity delivery charge, a $111 million increase due to the August 1, 2003 expiration of annual customer credits previously mandated by the New Jersey transition legislation, a $49 million increase in the MTC tariff component, and a net $1 million increase in the SBC. The MTC allows for the recovery of $465 million in deferred energy costs over the next ten years on an interim basis, thus disallowing $153 million of the $618 million provided for in a preliminary settlement agreement between certain parties. As a result, JCP&L recorded charges to net income for the year ended December 31, 2003, aggregating $185 million ($109 million net of tax) consisting of the $153 million of disallowed deferred energy costs and other regulatory assets. JCP&L filed aan August 15, 2003 interim motion for rehearing and reconsideration with the NJBPU and a June 1, 2004 supplemental and amended motion for rehearing and reconsideration. On July 7, 2004, the NJBPU granted limited reconsideration and rehearing on ~~August 15, 2003 with respect to~~ the following issues: (1) ~~the disallowance of the $153 million~~ deferred ~~energy costs;~~cost disallowances; (2) the ~~reduced~~capital structure including the rate of ~~return on equity; and~~return; (3) ~~$42.7 million~~merger savings, including amortization of ~~disallowed~~ costs to achieve merger ~~savings.~~ savings; and (4) decommissioning costs. Management is unable to predict when a decision may be reached by the NJBPU.

On ~~October 10, 2003,~~July 16, 2004, JCP&L filed the Phase II petition and testimony with the NJBPU, ~~held the motion~~requesting an increase in ~~abeyance until the final NJBPU decision and order which is expected to be issued in the second quarter~~base rates of ~~2004. JCP&L's BGS obligation~~$36 million for the ~~twelve month period beginning August 1, 2003~~recovery of system reliability costs and a 9.75% return on equity. The filing also requests an increase to the MTC deferred balance recovery of approximately $20 million annually. The Ratepayer Advocate filed testimony on November 16, 2004, and JCP&L submitted rebuttal testimony on January 4, 2005. The Ratepayer Advocate surrebuttal testimony was ~~auctioned in~~submitted February ~~2003. The auction covered a fixed price bid (applicable to all residential~~8, 2005. Discovery and ~~smaller commercial and industrial customers) and an hourly price bid (applicable to all large industrial customers) process.~~ settlement conferences are ongoing.

JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy ~~balances. The~~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 2004 auction for the ~~subsequent~~BGS supply became effective June 1, 2004. The auction for the supply period beginning June 1, 2005 was completed in February ~~2004.~~2005. The NJBPU ~~adjusted the generation component of JCP&L's retail rates~~decision on ~~August 1, 2003 to reflect the results of~~ the BGS ~~auction. On~~post transition year three process was announced on October 22, 2004, approving with minor modifications the BGS procurement process filed by JCP&L and the other New Jersey electric distribution companies and authorizing the continued use of NUG committed supply to serve 300 MW of BGS load.

In accordance with an April 28, 2004 ~~the~~ NJBPU ~~directed~~order, JCP&L ~~to file~~filed testimony ~~by the end of May~~on June 7, 2004 ~~either~~ supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey ~~ratepayers, or, alternatively, proposing~~customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L ~~cannot predict the outcome~~filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of ~~this matter. 15~~ Pennsylvania The PPUC authorized in 1998 rate restructuring plans for Penn, Met-Ed and Penelec. In 2000, the PPUC disallowed a portion of the requested additional stranded costs above those amounts granted in Met-Ed's and Penelec's 1998 rate restructuring plan orders. The PPUC required Met-Ed and Penelec to seek an IRS ruling regarding the return of certain unamortized investment tax credits and excess deferred income tax benefits to customers. Similar to JCP&L's situation, if the IRS ruling ultimately supports returning these tax benefits to customers, there would be no effect to FirstEnergy's, Met-Ed's or Penelec's net income since the contingency existed prior$729 million (in 2003 dollars) compared to the ~~merger and would be an adjustment~~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 ~~goodwill. In June 2001, the PPUC approved the Settlement Stipulation with all of the major parties in the combined merger and rate relief~~those comments. A schedule for further proceedings which approved the FirstEnergy/GPU merger and provided PLR deferred accounting treatment for energy costs, permitting Met-Ed and Penelec to defer, for future recovery, energy costs in excess of amounts reflected in their capped generation rates retroactive to January 1, 2001. This PLR deferral accounting procedure was later denied in ahas not yet been set.

Pennsylvania

A February 2002 Commonwealth Court of Pennsylvania ~~decision. The court~~ decision ~~also~~ affirmed the June 2001 PPUC decision regarding approval of the FirstEnergy/GPU merger, remanding the decision to the PPUC only with respect to the issue of merger savings. FirstEnergy established reserves in 2002 for Met-Ed's and Penelec's PLR deferred energy costs which aggregated $287.1 million, reflecting the potential adverse impact of the then pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court decision. As a result, FirstEnergy recorded in 2002 an aggregate non-cash charge of $55.8 million ($32.6 million net of tax) to income for the deferred costs incurred subsequent to the merger. The reserve for the remaining $231.3 million of deferred costs increased goodwill by an aggregate net of tax amount of $135.3 million. On April 2, 2003, the PPUC remanded the ~~issue relating to~~issues of quantification and allocation of merger savings to the ~~Office of Administrative Law for hearings, directed~~PPUC and denied Met-Ed and Penelec ~~to file a position paper on~~ the ~~effect of~~rate relief initially approved in the Commonwealth Court order on the Settlement Stipulation and allowed other parties to file responses to the position paper. Met-Ed and Penelec filed a letter with the ALJ on June 11, 2003, voiding the Settlement Stipulation in its entirety and reinstating Met-Ed's and Penelec's restructuring settlement previously approved by the PPUC. OnPPUC decision. In October 2, 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the ~~PPUC's~~PPUC’s June ~~20,~~ 2001 order in its entirety. ~~The PPUC directed~~In accordance with the PPUC's direction, Met-Ed and Penelec filed supplements to ~~file~~their tariffs ~~within thirty days of the order to reflect~~that were effective October 2003 and that reflected the CTC rates and shopping credits ~~that were~~ in effect prior to the June ~~21,~~ 2001 ~~order~~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. These companies' combined portion of total merger savings is estimated to be ~~effective upon one day's notice.~~ approximately $31.5 million. If no settlement can be reached, Met-Ed and Penelec will take the position that any portion of such savings should be allocated to customers during each company's next rate proceeding.

In response to ~~that order, Met-Ed and Penelec filed these supplements to~~ their ~~tariffs to become effective October 24, 2003. On~~ October 8, 2003 ~~Met-Ed and Penelec filed a~~ petition, ~~for clarification relating to~~ the ~~October 2, 2003 order on two issues: to establish~~PPUC approved June 30, 2004 as the date ~~to fully refund the~~for Met-Ed's and Penelec's NUG trust fund ~~and to clarify that~~refunds. The PPUC denied the ~~ordered~~ accounting ~~treatment~~request regarding the CTC rate/shopping credit swap should follow the ratemaking, and that the PPUC's findings would not impair their rights to recover all of their stranded costs. On October 9, 2003, ARIPPA (an intervenor in the proceedings) petitioned the PPUC to direct Met-Ed and Penelec to reinstate accounting for the CTC rate/shopping credit swap retroactive to January 1, 2002. Several other parties also filed petitions. On October 16, 2003, the PPUC issued a reconsideration order granting the date requested by Met-Ed and Penelec for the NUG trust fund refund, denying Met-Ed's and Penelec's other clarification requests and granting ARIPPA's petition with respect to the accounting treatment of the changes to the CTC rate/shopping credit swap. On October 22, 2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking that the Court reverse the PPUC's finding that requiresrequiring Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. ~~On October 27, 2003, a Commonwealth Court judge issued an Order denying Met-Ed's and Penelec's objection without explanation. Due to the vagueness of the Order,~~ Met-Ed and Penelec subsequently filed with the Commonwealth Court, on October 31, 2003, ~~filed~~ an Application for Clarification with the ~~judge. Concurrent with this filing, Met-Ed and Penelec, in order to preserve their rights, also filed with the Commonwealth Court both~~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~~Objection was intended to be denied on the merits. ~~In addition to these findings,~~ The Reargument Brief before the Commonwealth Court was filed January 28, 2005.

Met-Ed and Penelec in compliance with the PPUC's Orders, filed revised PPUC quarterly reports for the twelve months ended December 31, 2001 and 2002, and for the first two quarters of 2003, reflecting balances consistent with the PPUC's findings in their Orders. Effective September 1, 2002, Met-Ed and Penelec agreed to purchase a portion of their PLR requirements from FES through a wholesale power ~~sale~~sales agreement. The PLR sale ~~will be~~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 ~~assumed~~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. ~~FES has hedged most of Met-Ed's and Penelec's unfilled PLR on-peak obligation through 2004 and a portion of 16~~ ~~2005, the period during which deferred accounting was previously allowed under the PPUC's order.~~ Met-Ed and Penelec are authorized to continue deferring differences between NUG contract costs and current market prices. ~~In late~~

Transmission

On November 1, 2004, ATSI requested authority from the FERC to defer approximately $54 million of vegetation management costs ($14 million deferred as of March 31, 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.

ATSI and MISO filed with the FERC on December 2, 2004, seeking approval for ATSI to have transmission rates established based on a FERC-approved cost of service - formula rate included in Attachment O under the MISO tariff. The ATSI Network Service net revenue requirement increased under the formula rate to approximately $159 million. On January 28, 2005, the FERC accepted for filing the revised tariff sheets to become effective February 1, 2005, subject to refund, and ordered a public hearing be held to address the reasonableness of the proposal to eliminate the voltage-differentiated rate design for the ATSI zone. On April 4, 2005, a settlement with all parties to the proceeding was filed with the FERC that provides for recovery of the full amount of the rate increase permitted under the formula.

On December 30, 2004, the Ohio Companies filed an application with the PUCO seeking tariff adjustments to recover increases of approximately $30 million in transmission and ancillary service costs beginning January 1, 2006. The Ohio Companies also filed an application for authority to defer costs associated with MISO Day 1, MISO Day 2, congestion fees, FERC assessment fees, and the ATSI rate increase, as applicable, from October 1, 2003 through December 31, 2005.

On January 12, 2005, Met-Ed and Penelec filed a request with the PPUC ~~issued a Tentative Order implementing new reliability benchmarks and standards. In connection therewith,~~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 PPUC commenced a rulemaking procedure to amend the Electric Service Reliability Regulations to implement these new benchmarks, and create additional reporting on reliability. Although neither the Tentative Order nor the Reliability Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. The comment period for both the Tentative Ordercases above, and the Proposed Rulemaking Order has closed. Met-Ed, Penelec and Penn are currently awaiting the PPUC to issue a final order in both matters. The order will determine (1) the standards and benchmarks to be utilized, and (2) the details required in the quarterly and annual reports. Companies have not yet implemented deferral accounting for these costs.

On ~~January~~September 16, 2004, the ~~PPUC initiated~~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 decision, CEI may be responsible for a ~~formal investigation~~portion of whether Met-Ed's, Penelec's and Penn's "service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring" in Pennsylvania. Discovery has commencednew energy market charges imposed by MISO when its energy markets begin in the proceeding and Met-Ed's, Penelec's and Penn's testimony is due May 14, 2004. Hearings are scheduled to begin August 3, 2004 in this investigation and the ALJ has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order by year endspring of ~~2004. FirstEnergy is unable to predict the outcome~~2005. CEI filed for rehearing of the ~~investigation or~~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. 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

The EUOC recognize, as regulatory assets, costs which the FERC, PUCO, PPUC ~~order. 7~~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 - $250 million, CEI - $320 million, TE - $98 million, as of March 31, 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 March 31, 2005 for JCP&L, Met-Ed and Penelec are approximately $2.3 billion, $0.7 billion and $0.2 billion, respectively. Deferral of above-market costs from power supplied by NUGs to JCP&L are approximately $1.3 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 $0.2 billion, respectively. These costs are being recovered through CTC revenues. The regulatory asset for above-market NUG costs and a 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 for New Jersey and Pennsylvania.

14. - NEW ACCOUNTING STANDARDS AND ~~INTERPRETATIONS: EITF Issue~~INTERPRETATIONS

FIN 47,“Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. ~~03-6, "Participating Securities~~143”

On March 30, 2005, the FASB issued this interpretation 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 Two-Class Method Under Financial Accounting Standards Board Statement No. 128, Earnings per Share" On March 31, 2004, the FASB ratified the consensus reached by the EITF on Issue 03-6. The issue addresses a number of questions regarding the computation of earnings per share by companies that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of a company when, and if, it declares dividends on its common stock. The issue also provides further guidance in applying the two-class method of computing earnings per share once it is determined that a security is participating, including how to allocate undistributed earnings to such a security. EITF 03-6reasons why must be disclosed. This Interpretation is effective ~~for~~no later than the end of fiscal ~~periods beginning~~years ending after ~~March 31, 2004.~~December 15, 2005. FirstEnergy is currently evaluating the effect ~~of adopting EITF 03-6. FSP 106-1, "Accounting and Disclosure Requirements Related to~~this standard will have on its financial statements.

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

In December 2004, the ~~Medicare Prescription Drug, Improvement and Modernization Act of 2003" Issued January 12, 2004, FSP 106-1 permits a sponsor of a postretirement health care plan~~FASB issued this Statement amending APB 29, which was based on the principle that ~~provides a prescription drug benefit to make a one-time election to defer accounting for~~nonmonetary assets should be measured based on the ~~effects~~fair value of the ~~Medicare Act. FirstEnergy elected~~assets exchanged. The guidance in APB 29 included certain exceptions to ~~defer~~that principle. SFAS 153 eliminates the ~~effects~~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 ~~Medicare Act due~~entity are expected to ~~the lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004~~change significantly as a result of ~~a February 2, 2004 plan amendment that required remeasurement~~the exchange. The provisions of ~~the plan's obligations. See Note 2~~this statement are effective for ~~a discussion of the effect of the federal subsidy~~nonmonetary exchanges occurring in fiscal periods beginning after June 15, 2005 and plan amendment on the consolidated financial statements. FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" In December 2003, the FASB issued a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", referred to as FIN 46R, which requires the consolidation of a VIE by an enterprise if that enterprise is determinedare to be ~~the primary beneficiary of the VIE. As required,~~applied prospectively. FirstEnergy ~~adopted FIN 46R for interests in VIEs commonly referred~~is currently evaluating this standard but does not expect it to ~~as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. Adoption of FIN 46R did not~~ have a material impact on ~~FirstEnergy's~~its financial ~~statements for~~statements.

SFAS 123 (revised 2004),“Share-Based Payment”

In December 2004, the quarter ended March 31, 2004. See Note 2 for a discussion of variable interest entities. For the quarter ended March 31, 2004, FirstEnergy evaluated, among other entities, its power purchase agreements and determined that it is possible that nine NUG entities might be considered variable interest entities. FirstEnergy has requested but not received the information necessaryFASB issued this revision to determine whether these entities are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. In most cases, the requested information was deemed to be competitive and proprietary data. 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 increasesSFAS 123, which requires expensing stock options in the ~~variable pricing component under~~financial statements. Important to applying the ~~contract terms~~new standard is understanding how to (1) measure the fair value of stock-based compensation awards and ~~cannot~~(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 ~~determined~~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. 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 ~~requested data. Purchased power~~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 this statement to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs ~~from~~and wasted material (spoilage). Previous guidance stated that in some circumstances these ~~entities during~~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 ~~first quarters~~cost of 2004 and 2003 were $51 million (JCP&L - $28 million, Met-Ed - $16 million and Penelec - $7 million) and $56 million (JCP&L - $34 million, Met-Ed - $15 million and Penelec - $7 million), respectively.conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by FirstEnergy after June 30, 2005. FirstEnergy is ~~required~~currently evaluating this standard but does not expect it to ~~continue to make exhaustive 17~~ efforts to obtain the necessary information in future periods and is unable to determine the possible impact of consolidating any such entity without this information. EITF Issue No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not "Held for Trading Purposes" as Defined in EITF Issue 02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." In July 2003, the EITF reached a consensus that determining whether realized gains and losses on physically settled derivative contracts not "held for trading purposes" should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. The consideration of the facts and circumstances, including economic substance, should be made in the context of the various activities of the entity rather than based solely on the terms of the individual contracts. The adoption of this consensus effective January 1, 2004, did not have a material impact on the ~~Companies'~~ financial statements. 8

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”

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 9 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 No. 109,“Accounting for Income Taxes.” FirstEnergy is currently evaluating this FSP but does not expect it to have a material impact on the Company's financial statements.

15. - SEGMENT INFORMATION:

FirstEnergy ~~operates under two~~has three reportable segments: regulated services, power supply management services (referred to as competitive electric energy services in previous filings) and ~~competitive~~facilities (HVAC) services. The aggregate ~~"Other"~~“Other” segments do not individually meet the criteria to be considered a reportable segment. ~~"Other" consists of interest expense related to holding company debt; corporate support services and the international businesses acquired in the 2001 merger.~~ 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 EUOC in Ohio, Pennsylvania and New ~~Jersey (OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec and ATSI).~~Jersey. The ~~competitive~~power supply management services ~~business~~ segment primarily consists of the subsidiaries (FES, ~~FSG, MYR, MARBEL~~FGCO and ~~FirstCom)~~FENOC) that sell electricity in deregulated markets and operate ~~unregulated energy and energy-related businesses, including~~ the ~~operation of~~ 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 ~~(see Note 6 - Regulatory Matters).~~ 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 ~~costs~~cost recovery. Assets of the regulated services segment include generating units that are leased to the power supply management services. The ~~competitive~~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 generation ~~operations as discussed under Note 6. As a result, its revenues include~~operations. Its net income is primarily derived from all electric generation ~~electric~~ sales revenues, ~~(including the~~which consist of generation services to regulated franchise customers who have not chosen an alternative generation ~~supplier)~~supplier, retail sales in deregulated markets and all domestic unregulated ~~energy and energy-related services including commodity~~electricity sales ~~(both electricity and natural gas)~~ in the retail and wholesale markets ~~marketing,~~less the related costs of electricity generation and sourcing of commodity ~~requirements, providing local~~requirements. Its net income also reflects the expense of the intersegment generating unit leases discussed above and ~~long-distance phone service, as well as other competitive energy-application services.~~ property tax amounts related to those generating units.

Segment reporting for interim periods in ~~2003~~2004 was reclassified to conform with the current year business segment ~~organizations~~organization and ~~operations. Revenues from the competitive services segment now include all generation revenues including generation services to~~operations emphasizing FirstEnergy's regulated ~~franchise customers previously reported under the regulated services segment~~electric businesses and ~~now exclude revenues from~~ power supply ~~agreements with the regulated services segments previously reported as internal revenues. The regulated services segment results now exclude generation sales revenues~~management operations and related generation commodity costs. Certain amounts (including transmission and congestion charges) were reclassified among purchased power, other operating costs and depreciation and amortization to conform with the current year presentation of generation commodity costs. In addition, segment results have been adjusted to reflect the reclassification of ~~revenue, expense, interest expense and tax amounts of divested businesses reflected as~~ discontinued operations (see Note 2)6). 18

A previous reportable segment was the more expansive competitive services segment whose aggregate operations consisted of FirstEnergy generation operations, natural gas commodity sales, providing local and long-distance phone service and other competitive energy-related businesses such as facilities services and construction service (MYR). Management's focus is on its core electric business. This has resulted in a change in performance review analysis from an aggregate view of all competitive services operations to a focus on its power supply management services operations. During FirstEnergy's periodic review of reportable segments under SFAS 131, that change resulted in the revision of reportable segments to the separate reporting of power supply management services and facilities services and including all other competitive services operations in the "Other" segment. Facilities services 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 two 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
Three Months Ended	*(In millions)*
March 31, 2005
External revenues	$	1,339	$	1,295		$	56		$	112	$	11		$	2,813
Internal revenues		78		--			--			--		(78	)		--
Total revenues		1,417		1,295			56			112		(67	)		2,813
Depreciation and amortization		377		10			--			1		6			394
Net interest charges		98		10			--			1		62			171
Income taxes		155		(25	)		(3	)		10		(16	)		121
Income before discontinued operations		223		(36	)		(2	)		5		(49	)		141
Discontinued operations		--		--			13			6		--			19
Net income		223		(36	)		11			11		(49	)		160
Total assets		28,540		1,582			83			495		561			31,261
Total goodwill		5,947		24			--			63		--			6,034
Property additions		141		81			1			2		4			229

March 31, 2004
External revenues	$	1,290	$	1,522		$	58		$	116	$	11		$	2,997
Internal revenues		79		--			--			--		(79	)		--
Total revenues		1,369		1,522			58			116		(68	)		2,997
Depreciation and amortization		393		9			1			--		9			412
Net interest charges		105		11			--			1		54			171
Income taxes		145		(1	)		(1	)		3		(31	)		115
Income before discontinued operations		213		(2	)		(1	)		5		(42	)		173
Discontinued operations		--		--			--			1		--			1
Net income		213		(2	)		(1	)		6		(42	)		174
Total assets		29,336		1,426			167			778		878			32,585
Total goodwill		5,981		24			37			75		--			6,117
Property additions		91		44			1			--		2			138

Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial ~~reporting: (a) Principally~~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. (b) Elimination~~purposes, and elimination of intersegment transactions.

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

		Three Months Ended
		March 31,
		2005			2004

	*(In thousands, except per share amounts)*
REVENUES:
Electric utilities		$	2,308,516		$	2,177,033
Unregulated businesses (Note 2)			504,196			819,505
Total revenues			2,812,712			2,996,538

EXPENSES:
Fuel and purchased power (Note 2)			895,332			1,134,326
Other operating expenses			905,388			812,642
Provision for depreciation			142,632			145,850
Amortization of regulatory assets			310,841			310,202
Deferral of new regulatory assets			(59,507	)		(44,405	)
General taxes			185,179			178,990
Total expenses			2,379,865			2,537,605

INCOME BEFORE INTEREST AND INCOME TAXES			432,847			458,933

NET INTEREST CHARGES:
Interest expense			164,657			172,510
Capitalized interest			(255	)		(6,470	)
Subsidiaries’ preferred stock dividends			6,553			5,281
Net interest charges			170,955			171,321

INCOME TAXES			121,104			115,086

INCOME BEFORE DISCONTINUED OPERATIONS			140,788			172,526

Discontinued operations (net of income taxes (benefit) of ($7,598,000)
and $1,028,000, respectively) (Note 6)			18,938			1,473

NET INCOME		$	159,726		$	173,999

BASIC EARNINGS PER SHARE OF COMMON STOCK:
Income before discontinued operations		$	0.43		$	0.53
Discontinued operations (Note 6)			0.06			--
Net income		$	0.49		$	0.53

WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING			327,908			327,057

DILUTED EARNINGS PER SHARE OF COMMON STOCK:
Income before discontinued operations		$	0.42		$	0.53
Discontinued operations (Note 6)			0.06			--
Net income		$	0.48		$	0.53

WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING			329,427			329,034

DIVIDENDS DECLARED PER SHARE OF COMMON STOCK		$	0.4125		$	0.375


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

19 ~~FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF INCOME (Unaudited)~~

~~FIRSTENERGY CORP. CONSOLIDATED BALANCE SHEETS (Unaudited)~~

~~FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)~~

~~REPORT OF INDEPENDENT ACCOUNTANTS~~

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,

	2005			2004

	*(In thousands)*

NET INCOME	$	159,726		$	173,999

OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gain on derivative hedges		7,323			1,365
Unrealized gain (loss) on available for sale securities		(7,986	)		16,938
Other comprehensive income		(663	)		18,303
Income tax related to other comprehensive income		129			(9,480	)
Other comprehensive income (loss), net of tax		(534	)		8,823

COMPREHENSIVE INCOME	$	159,192		$	182,822


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

FIRSTENERGY CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,			December 31,
		2005			2004
		*(In thousands)*
ASSETS	��
CURRENT ASSETS:
Cash and cash equivalents		$	81,191		$	52,941
Receivables-
Customers (less accumulated provisions of $31,457,000 and
$34,476,000, respectively, for uncollectible accounts)			983,488			979,242
Other (less accumulated provisions of $32,807,000 and
$26,070,000, respectively, for uncollectible accounts)			275,355			377,195
Materials and supplies, at average cost-
Owned			378,951			363,547
Under consignment			98,917			94,226
Prepayments and other			248,388			145,196
			2,066,290			2,012,347
PROPERTY, PLANT AND EQUIPMENT:
In service			22,294,674			22,213,218
Less - Accumulated provision for depreciation			9,479,701			9,413,730
			12,814,973			12,799,488
Construction work in progress			735,090			678,868
			13,550,063			13,478,356
INVESTMENTS:
Nuclear plant decommissioning trusts			1,604,062			1,582,588
Investments in lease obligation bonds			918,632			951,352
Other			734,419			740,026
			3,257,113			3,273,966
DEFERRED CHARGES:
Regulatory assets			5,606,433			5,532,087
Goodwill			6,033,728			6,050,277
Other			746,936			720,911
			12,387,097			12,303,275
		$	31,260,563		$	31,067,944
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt		$	960,168		$	940,944
Short-term borrowings			310,125			170,489
Accounts payable			663,018			610,589
Accrued taxes			687,341			657,219
Other			1,022,302			929,194
			3,642,954			3,308,435
CAPITALIZATION:
Common stockholders’ equity-
Common stock, $.10 par value, authorized 375,000,000 shares-
329,836,276 shares outstanding			32,984			32,984
Other paid-in capital			7,058,484			7,055,676
Accumulated other comprehensive loss			(313,646	)		(313,112	)
Retained earnings			1,881,047			1,856,863
Unallocated employee stock ownership plan common stock-
1,821,553 and 2,032,800 shares, respectively			(37,916	)		(43,117	)
Total common stockholders' equity			8,620,953			8,589,294
Preferred stock of consolidated subsidiaries			238,719			335,123
Long-term debt and other long-term obligations			9,719,893			10,013,349
			18,579,565			18,937,766
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			2,346,766			2,324,097
Asset retirement obligations			1,095,105			1,077,557
Power purchase contract loss liability			2,160,867			2,001,006
Retirement benefits			1,255,077			1,238,973
Lease market valuation liability			915,050			936,200
Other			1,265,179			1,243,910
			9,038,044			8,821,743
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 12)
		$	31,260,563		$	31,067,944

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

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31,
	2005			2004

	*(In thousands)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	159,726		$	173,999
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		142,632			145,850
Amortization of regulatory assets		310,841			310,202
Deferral of new regulatory assets		(59,507	)		(44,405	)
Nuclear fuel and lease amortization		18,648			21,874
Other amortization, net		(5,451	)		(4,723	)
Deferred purchased power and other costs		(109,233	)		(83,907	)
Deferred income taxes and investment tax credits, net		(14,156	)		5,923
Deferred rents and lease market valuation liability		(35,663	)		(16,297	)
Accrued retirement benefit obligations		16,103			24,636
Accrued compensation, net		(41,722	)		4,387
Commodity derivative transactions, net		187			(30,787	)
Income from discontinued operations (Note 6)		(18,938	)		(1,473	)
Decrease (Increase) in operating assets:
Receivables		90,663			272,746
Materials and supplies		7,457			21,580
Prepayments and other current assets		(106,122	)		(47,031	)
Increase (Decrease) in operating liabilities:
Accounts payable		61,419			(177,018	)
Accrued taxes		40,712			30,902
Accrued interest		108,601			86,281
Other		2,593			(44,888	)
Net cash provided from operating activities		568,790			647,851

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		--			581,558
Short-term borrowings, net		139,811			--
Redemptions and Repayments-
Preferred stock		(97,900	)		--
Long-term debt		(235,888	)		(268,920	)
Short-term borrowings, net		--			(387,541	)
Net controlled disbursement activity		(29,937	)		(42,656	)
Common stock dividend payments		(135,306	)		(122,465	)
Net cash used for financing activities		(359,220	)		(240,024	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(228,884	)		(138,406	)
Proceeds from asset sales		53,724			11,439
Nonutility generation trust contributions		--			(50,614	)
Contributions to nuclear decommissioning trusts		(25,370	)		(25,370	)
Cash investments		26,904			20,218
Other		(7,694	)		(58,800	)
Net cash used for investing activities		(181,320	)		(241,533	)

Net increase in cash and cash equivalents		28,250			166,294
Cash and cash equivalents at beginning of period		52,941			113,975
Cash and cash equivalents at end of period	$	81,191		$	280,269

The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part ofthese 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 March 31, ~~2004,~~2005, and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, ~~2004~~2005 and ~~2003.~~2004. These interim financial statements are the responsibility of the ~~Company's~~Company’s management.

We conducted our review in accordance with the standards ~~established by~~of the ~~American Institute of Certified~~ Public ~~Accountants.~~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 ~~generally accepted auditing~~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.

We previously audited, in accordance with ~~auditing~~the standards ~~generally accepted in~~of the ~~United States of America,~~Public Company Accounting Oversight Board (United States), the consolidated balance sheet ~~and the consolidated statement of capitalization~~ as of December 31, ~~2003,~~2004, and the related consolidated statements of income, capitalization, common ~~stockholders'~~stockholders’ equity, preferred stock, cash flows and taxes for the year then ended, ~~(not presented herein),~~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~~Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note ~~2(F)~~2(K) to those consolidated financial statements and the ~~Company's~~Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 97 to those consolidated financial statements) dated ~~February 25, 2004,~~March 7, 2005, we expressed an unqualified ~~opinion on those~~opinions thereon. The consolidated financial ~~statements.~~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 ~~condensed~~ consolidated balance sheet information as of December 31, ~~2003,~~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

May ~~7, 2004~~ 3, 2005

FIRSTENERGY CORP. ~~MANAGEMENT'S~~

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION ~~FirstEnergy's Business~~

EXECUTIVE SUMMARY

Net income in the first quarter of 2005 was $160 million, or basic earnings of $0.49 per share of common stock ($0.48 diluted), compared to net income of $174 million, or basic and diluted earnings of $0.53 per share of common stock for the first quarter of 2004. During the quarter, FirstEnergy ~~Corp.~~continued to divest non-core assets, including the sale of FirstEnergy’s retail natural gas business. These activities resulted in a combined net gain for the quarter of $0.07 per share of common stock.

The impact of costs associated with FirstEnergy’s settlement of the W. H. Sammis New Source Review (NSR) case and a proposed NRC fine related to the 2002 outage at the Davis-Besse nuclear power plant reduced earnings for the quarter by $0.05 per share of common stock. Also, nuclear operation and maintenance cost increases associated with the scheduled outages at the Davis-Besse and Perry nuclear power plants, combined with an unplanned outage at the Perry plant, reduced earnings per share by $0.12 compared with the first quarter of 2004.

On March 18, 2005, FirstEnergy announced that it had reached a settlement with the U.S. EPA, the U.S. Department of Justice, and three states that resolved all issues related to various parties’ actions against FirstEnergy’s W. H. Sammis Plant in the pending NSR case. The agreement, which is in the form of a consent decree, also was signed by the states of Connecticut, New Jersey and New York and was filed with the Court.

Under the agreement, FirstEnergy will install environmental controls at all seven units of the Sammis Plant, as well as at other power plants. FirstEnergy will also upgrade existing scrubber systems on units 1 through 3 of its Bruce Mansfield Plant. Projects at the Sammis Plant will include equipment designed to reduce 95 percent of SO₂ emissions and 90 percent of NO_x emissions on the plant’s two largest units. Additionally, the plant’s five smaller units will be controlled by equipment designed to reduce at least 50 percent of SO₂ and 70 percent of NO_x emissions. In total, additional environmental controls could be installed on nearly 5,500 MW of FirstEnergy’s 7,400 MW coal-based generating capacity, with construction beginning in 2005 and completed no later than 2012. The estimated $1.1 billion investment in environmental improvements is consistent with assumptions reflected in the Companies’ long-term financial planning.

On March 15, 2005, members of the International Brotherhood of Electrical Workers System Council U-3 ratified a new four-year contract with FirstEnergy subsidiary JCP&L. Ratification of the contract resolved issues surrounding health care and work rules, and ended a 14-week strike against JCP&L by the Council’s members.

FIRSTENERGY’S BUSINESS

FirstEnergy is a registered public utility holding company headquartered in Akron, Ohio that provides regulated and competitive energy services (see Results of Operations - Business Segments). FirstEnergy continues to pursue its goal of being the leading supplier of energy and related services in portions of the midwest and mid-Atlantic regions of the United States, where it sees the best opportunities for growth. FirstEnergy's fundamentaloperates primarily through two core business strategy remains stable and unchanged. While FirstEnergy continues to build toward a strong regional presence, key elements for its strategy are in place and management's focus continues to be on execution. FirstEnergy intends to continue providing competitively priced, high-quality products and value-added services - energy sales and services, energy delivery, power supply and supplemental services related to its core business. As the industry changes to a more competitive environment, FirstEnergy has taken and expects to take actions designed to create a larger, stronger regional enterprise that will be positioned to compete in the changing energy marketplace. FirstEnergy'ssegments.

Regulated Services transmit, distribute and sell 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 ManagementServices 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 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 companies provide transmission and distribution services and 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. Competitive services are principally provided by FES, FSG, MARBEL, MYR and FirstEnergy's majority owned FirstCom. Through its 50% interest in GLEP, MARBEL is involved in the exploration and production of oil and natural gas, and transmission and marketing of natural gas. Other subsidiariessegments provide a wide range of services, including heating, ventilation, air-conditioning, refrigeration, process piping, plumbing, electrical and facility control systems, high-efficiency electrotechnologies and ~~high-efficiency electrotechnologies. Telecommunication services are also provided - local~~telecommunication services. FirstEnergy continues to divest these non-core businesses. See Note 6 to the consolidated financial statements.

RESULTS OF OPERATIONS

The financial results discussed below include revenues and ~~long-distance phone service~~expenses from transactions among our business segments. A reconciliation of segment financial results is provided in Note 15 to ~~more than 65,000 customers. While competitive revenues have increased since 2001, regulated energy services continue~~the consolidated financial statements. The FSG business segment is included in "Other and Reconciling Adjustments" in this discussion due to ~~provide,~~its immaterial impact on current period financial results, but is presented separately in ~~aggregate,~~segment information provided in Note 15 to the ~~majority of FirstEnergy's~~consolidated financial statements. Net income (loss) by major business segment was as follow:

	Three Months Ended
	March 31,						Increase
	2005			2004			(Decrease)
Net Income (Loss)	*(In millions)*
By Business Segment
Regulated services	$	223		$	213		$	10
Power supply management services		(36	)		(2	)		(34	)
Other and reconciling adjustments*		(27	)		(37	)		10
Total	$	160		$	174		$	(14	)

Basic Earnings Per Share:
Income before discontinued operations	$	0.43		$	0.53		$	(0.10	)
Discontinued operations	$	0.06		$	--		$	0.06
Net Income	$	0.49		$	0.53		$	(0.04	)

Diluted Earnings Per Share:
Income before discontinued operations	$	0.42		$	0.53		$	(0.11	)
Discontinued operations	$	0.06		$	--		$	0.06
Net Income	$	0.48		$	0.53		$	(0.05	)

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

services revenues and earnings. Beginning in 2001, Ohio utilities that offered both competitive and regulated retail electric services were required to implement a corporate separation plan approved by the PUCO - one which provided a clear separation between regulated and competitive operations. FES provides competitive retail energy services while the EUOC provide regulated transmission and distribution services. FGCO, a wholly owned subsidiary of FES, leases fossil and hydroelectric plants from the EUOC and operates those plants. Under the terms of the current corporate separation plan, the transfer of ownership of EUOC non-nuclear generating assets to FGCO would be substantially completed by the end of the Ohio market development period. All of the EUOC power supply requirements for the Ohio Companies (OE, CEI, and TE) and Penn are provided by FES to satisfy their PLR obligations, as well as their grandfathered wholesale contracts. FirstEnergy acquired international assets through the merger with GPU in November 2001. GPU Capital and its subsidiaries provided electric distribution services in foreign countries (see Results of Operations - Discontinued Operations). GPU Power and its subsidiaries owned and operated generation facilities in foreign countries. As of January 30, 2004, substantially all of the international operations were divested (see Note 5) - supporting FirstEnergy's commitment to focus on its core electric business. FirstEnergy's current focus includes: (1) enhancing customer service; (2) optimizing its generation portfolio; (3) minimizing unplanned extended generation outages; (4) effectively managing commodity supplies and risks; (5) reducing its cost structure; (6) enhancing its credit profile and financial flexibility; (7) managing the skills and diversity of its workforce; (8) continuing safe operations; and (9) satisfactory resolution of the pending Ohio rate plan. Reclassifications As further discussed in Note 8 to the Consolidated Financial Statements, amounts for purchased power, other operating costs and provisions for depreciation and amortization in FirstEnergy's 2003 Consolidated Statements of Income were reclassified to conform with the current year presentation of generation commodity costs. These reclassifications did not change previously reported 2003 results. In addition, as discussed in Note 2 to the Consolidated Financial Statements, reporting of discontinued operations also resulted in the reclassification of revenues, expenses and taxes. 24 ~~Results of Operations Net Income and Earnings Per Share~~ expenses.

Net income in the first quarter of 2004 was $174 million or $0.53 per share of common stock (basic and diluted), compared to $218 million or $0.74 per share of common stock (basic and diluted) in the first quarter of 2003. Net income in the first quarter of 20032005 included after-tax earnings from discontinued operations of $19 million ($0.06 per basic and diluted share) resulting from FirstEnergy’s disposition of non-core assets and operations. In the first quarter of 2005, discontinued operations included $17 million from net gains on sales (see“Other - First Quarter 2005 Compared to First Quarter 2004” below) and $2 million ~~and an after-tax credit~~from operations. In the first quarter of ~~$102~~2004, net income included $1 million from ~~the cumulative effect of an accounting change (basic~~discontinued operations.

A decrease in wholesale electric revenues and ~~diluted earnings per share of $0.35) due to the adoption of SFAS 143. Excluding the cumulative effect of the accounting change~~purchased power costs in the first quarter of ~~2003, earnings increased to $0.53 per share of common stock (basic~~2005 from the same period last year resulted from FES recording PJM sales and diluted) from $0.39 per share of common stock (basic and diluted). Two major factors contributed to this improved performance -- reduced maintenance costs incurred as part of the extended outage at Davis-Besse (as the plant prepared for restart in 2004) and the absence of any nuclear refueling outagepurchased power transactions on an hourly net position basis beginning in the first ~~three months~~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 was caused by the dedication of FirstEnergy’s Beaver Valley Plant to PJM in January 2005. FirstEnergy believes that this economic change required a net presentation of revenues and purchased power transactions as these generation assets are now dedicated in PJM where FirstEnergy has third-party customers. Wholesale electric revenues and purchased power costs in the first quarter of 2004 ~~versus one~~each included $280 million of these transactions recorded on a gross basis.

Excluding the effect of recording the wholesale electric revenue transactions in PJM on a gross basis in 2004, first quarter 2005 operating revenues were modestly higher. Net income declined primarily due to increased nuclear production costs from refueling ~~outage~~outages and the Sammis environmental settlement. Results for the first quarter of 2005 were enhanced by reduced employee benefit costs (see“Postretirement Plans” below), gains on the sale of assets and reduced fossil production costs.

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

				Power
				Supply			Other and
1^st Quarter 2005	Regulated			Management			Reconciling			FirstEnergy
Financial Results	Services			Services			Adjustments			Consolidated
	*(In millions)*

Revenue:
External
Electric	$	1,162		$	1,275		$	--		$	2,437
Other		177			20			179			376
Internal		78			--			(78	)		--
Total Revenues		1,417			1,295			101			2,813
Expenses:
Fuel and purchased power		--			895			--			895
Other operating		418			409			79			906
Provision for depreciation		126			10			7			143
Amortization of regulatory assets		311			--			--			311
Deferral of new regulatory assets		(60	)		--			--			(60	)
General taxes		146			32			7			185
Total Expenses		941			1,346			93			2,380

Net interest charges		98			10			63			171
Income taxes		155			(25	)		(9	)		121
Income before discontinued operations		223			(36	)		(46	)		141
Discontinued operations		--			--			19			19
Net Income	$	223		$	(36	)	$	(27	)	$	160

				Power
				Supply			Other and
1^st Quarter 2004	Regulated			Management			Reconciling			FirstEnergy
Financial Results	Services			Services			Adjustments			Consolidated
	*(In millions)*

Revenue:
External
Electric	$	1,154		$	1,502		$	--		$	2,656
Other		136			20			185			341
Internal		79			--			(79	)		--
Total Revenues		1,369			1,522			106			2,997
Expenses:
Fuel and purchased power		--			1,134			--			1,134
Other operating		366			346			101			813
Provision for depreciation		127			9			10			146
Amortization of regulatory assets		310			--			--			310
Deferral of new regulatory assets		(44	)		--			--			(44	)
General taxes		147			25			7			179
Total Expenses		906			1,514			118			2,538

Net interest charges		105			11			55			171
Income taxes		145			(1	)		(29	)		115
Income before discontinued operations		213			(2	)		(38	)		173
Discontinued operations		--			--			1			1
Net Income	$	213		$	(2	)	$	(37	)	$	174

				Power
Change Between				Supply			Other and			FirstEnergy
1^st Quarter 2005 and 2004	Regulated			Management			Reconciling			Consolidated
Financial Results	Services			Services			Adjustments			Total
Increase (Decrease)	*(In millions)*

Revenue:
External
Electric	$	8		$	(227	)	$	--		$	(219	)
Other		41			--			(6	)		35
Internal		(1	)		--			1			--
Total Revenues		48			(227	)		(5	)		(184	)
Expenses:
Fuel and purchased power		--			(239	)		--			(239	)
Other operating		52			63			(22	)		93
Provision for depreciation		(1	)		1			(3	)		(3	)
Amortization of regulatory assets		1			--			--			1
Deferral of new regulatory assets		(16	)		--			--			(16	)
General taxes		(1	)		7			--			6
Total Expenses		35			(168	)		(25	)		(158	)

Net interest charges		(7	)		(1	)		8			--
Income taxes		10			(24	)		20			6
Income before discontinued operations		10			(34	)		(8	)		(32	)
Discontinued operations		--			--			18			18
Net Income	$	10		$	(34	)	$	10		$	(14	)

Regulated Services - First Quarter 2005 Compared to First Quarter 2004

Net income increased to $223 million from $213 million (or 5%) in the first 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
Revenues	March 31,				Increase
By Type of Service	2005		2004		(Decrease)
	*(In millions)*

Distribution services	$	1,162	$	1,154	$	8
Transmission services		92		62		30
Lease revenue from affiliates		78		79		(1	)
Other		85		74		11
Total Revenues	$	1,417	$	1,369	$	48

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

	Increase
Electric Distribution Deliveries	(Decrease)
Residential		(0.6	)%
Commercial		4.7	%
Industrial		4.3	%
Total Distribution Deliveries		2.6	%

Increased consumption offset in part by lower prices resulted in higher distribution delivery revenue. The following table summarizes major factors contributing to the $8 million increase in distribution service revenue in the first quarter of 2005:

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

Changes in customer usage	$	23
Changes in prices:
Rate changes --
Ohio shopping incentive		(11	)
Other		1
Rate mix & other		(5	)

Net Increase in Distribution Revenues	$	8

Transmission revenues increased $30 million in the first quarter of 2005 from the same period last year due in part to an amended power supply agreement with FES in June 2004. The amended agreement resulted in the regulated services segment assuming certain transmission revenues and expenses that were previously attributed to FES.

Other revenues increased $11 million primarily due to a payment received under a contract provision associated with the prior sale of TMI. Under the contract, additional payments are received if subsequent energy prices rise above specified levels. These payments are passed along to JCP&L, Met-Ed and Penelec customers, resulting in no net earnings effect.

Expenses-

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

·	Higher transmission expense of $43 million due in part to an amended power supply agreement with FES, which also increased revenue and other operating costs of $9 million; and

·	Increased income taxes of $10 million due to increased taxable income.

Partially offsetting these higher costs were two factors:

·	Additional deferrals of regulatory assets of $16 million, primarily representing shopping incentives and interest on those deferrals; and

·	Lower interest charges of $7 million primarily due to debt and preferred stock redemptions.

Power Supply Management Services - First Quarter 2005 Compared to First Quarter 2004

The net loss for this segment increased to $36 million in the first quarter of 2005 from a net loss of $2 million in the same period last year. ~~In the third quarter of 2003, FirstEnergy completed the issuance and sale of 32.2 million shares of common stock (see Cash Flows from Financing Activities below) which were included~~An improvement in the ~~calculation of earnings per share on a weighted average basis~~gross generation margin was more than offset by higher non-fuel nuclear costs, resulting in the ~~first quarter of 2004.~~ increased net loss.

Generation Margin -

The additional shares reduced earnings per share of common stock by $0.06 (basic and diluted). Three Months Ended March 31, ----------------------- FirstEnergy 2004 2003 ----------------------------------------------------------------------- (In millions) Total revenues............................. $3,183 $3,221 Income before interest and income taxes.... 462 414 Income before discontinued operations and cumulative effect of accounting change 174 114 Discontinued operations.................... -- 2 Cumulative effect of accounting change..... -- 102 ----------------------------------------------------------------------- Net Income................................. $ 174 $ 218 ----------------------------------------------------------------------- Basic Earnings Per Share: Income before discontinued operations and cumulative effect of accounting change $0.53 $0.39 Discontinued operations................. -- -- Cumulative effect of accounting change.. -- 0.35 ------------------------------------------------------------------------ Net Income................................. $0.53 $0.74 ======================================================================== Diluted Earnings Per Share: Income before discontinued operations and cumulative effect of accounting change $0.53 $0.39 Discontinued operations................. -- -- Cumulative effect of accounting change.. -- 0.35 ------------------------------------------------------------------------ Net Income................................. $0.53 $0.74 ======================================================================== Results of Operations - First Quarter of 2004 Compared With the First Quarter of 2003 Total revenues decreased $38 million in the first quarter of 2004, compared to the same period last year. The sources of changes in total revenues are summarized in the following table: 25 Three Months Ended March 31, ------------------ Increase Sources of Revenue Changes 2004 2003 (Decrease) --------------------------------------------------------------------- (In millions) Retail Electric Sales: EUOC - Wires and shopping deferrals $ 1,159 $ 1,213 $ (54) - Generation 758 785 (27) FES.............................. 171 121 50 Wholesale Electric Sales: EUOC............................. 124 221 (97) FES.............................. 444 284 160 ------------------------------------------------------------------ Electric Sales..................... 2,656 2,624 32 ------------------------------------------------------------------ Transmission Revenues.............. 76 9 67 Gas Sales.......................... 165 245 (80) Other Revenues: Regulated services................ 60 86 (26) Competitive services.............. 220 222 (2) International...................... -- 8 (8) Other.............................. 6 27 (21) ------------------------------------------------------------------- Total Revenues..................... $3,183 $3,221 $ (38) =================================================================== Changes in electric generation sales and distribution deliveries in the first quarter of 2004 from the same quarter of 2003 are summarized in the following table: Increase Changes in KWH Sales (Decrease) ----------------------------------------------------- Electric Generation Sales: Retail - EUOC.................................. (6.2)% FES................................... 24.4 % Wholesale............................... 19.5 % ----------------------------------------------------- Total Electric Generation Sales.......... 4.1 % ===================================================== EUOC Distribution Deliveries: Residential............................. (0.2)% Commercial.............................. -- % Industrial.............................. 0.8 % ----------------------------------------------------- Total Distribution Deliveries............ 0.2 % ===================================================== Retail sales by FirstEnergy's EUOC remain the largest source of revenues, contributing over 70% of electric revenues and over 60% of total revenues. The following major factors contributed to the $81 million reduction in retail electric revenues from FirstEnergy's regulated services segment in the first quarter of 2004 compared to the same period in 2003. Sources of the Changes in EUOC Retail Electric Revenue ------------------------------------------------------ Increase (Decrease) (In millions) ------------------------------------------------------ Changes in Demand: Alternative suppliers.................. $(56) Economic and other ................... 3 ------------------------------------------------------ (53) ------------------------------------------------------ Changes in Price: Rate changes........................... (32) Shopping credit........................ (7) Rate mix and other..................... 11 ------------------------------------------------------ (28) ------------------------------------------------------ Net Decrease............................. $ (81) ====================================================== Reductions in both demand and prices contributed to lower EUOC retail electric revenues. Customers shopping in FirstEnergy's franchise areas for alternative energy suppliers remained the largest single factor for the reduced demand. Alternative suppliers provided 24.1% of the total energy delivered to retail customers in the first quarter of 2004, compared to 18.9% in the same period of 2003. Distribution throughput increased slightly. Milder weather in the first quarter of 2004 compared to the unusually cold temperatures in the first quarter of 2003 contributed to reduced residential deliveries. However, economic and other factors contributed to increased industrial deliveries in the first quarter of 2004 compared to the same period last year. On July 25, 2003, the NJBPU announced its JCP&L base electric rate proceeding decision (see Regulatory Matters - New Jersey), which reduced JCP&L's distribution rates effective August 1, 2003. The lower rates reduced revenues by $32 million in the first quarter of 2004. EUOC sales to wholesale customers decreased by $97 26 million on a 44.1% reduction in kilowatt-hour sales - JCP&L's sales represented substantially all of the decrease. Electric sales by FES increased by $210 million primarily from additional spot sales to the wholesale market ($160 million). Higher electric sales to the wholesale market resulted from an 11% increase in internal generation available from FirstEnergy's nuclear (15%) and fossil (9%) generating plants. Retail sales increased by $50 million, primarily from customers within FirstEnergy's Ohio franchise areas switching to FES under Ohio's electricity choice program. FirstEnergy's regulated and unregulated subsidiaries record purchase and sales transactions with PJM on a gross basis in accordance with EITF 99-19. This gross basis classification of revenues and costs may not be comparable to other energy companies that operate in regions that have not established ISOs and do not meet EITF 99-19 criteria. The aggregate purchase and sales transactions for the three months ended March 31, 2004 and 2003 are summarized as follows: Three Months Ended March 31, ---------------------- 2004 2003 ------------------------------------------------------- (In millions) Sales......................... $366 $336 Purchases..................... 330 361 -------------------------------------------------------- FirstEnergy's revenues on the Consolidated Statements of Income include wholesale electricity sales revenues from PJM from power sales (as reflected in the table above) during periods when it had additional available power capacity. Revenues also include sales by FirstEnergy of power sourced from the PJM (reflected as purchases in the table above) during periods when it required additional power to meet FirstEnergy's retail load requirements and, secondarily, to sell to the wholesale market. Natural gas sales were $80 million lower primarily due to the expiration of FES customer choice program contracts and reduced sales to large industrial and commercial customers. Sales to large commercial and industrial customers declined in the first quarter of 2004 from the same period in 2003 reflecting fewer customers and more moderate temperatures. The generation margin in the first quarter of ~~2004~~2005 improved by ~~$53~~$12 million compared to the same period of 2004, as shown in ~~2003 as electric generation~~the table below.

Gross Generation Margin	2005		2004		Increase (Decrease)
	*(In millions)*
Electric generation revenue	$	1,275	$	1,502	$	(227	)
Fuel and purchased power costs		895		1,134		(239	)
Gross Generation Margin	$	380	$	368	$	12

Revenues - -

Excluding the effect of the change in recording PJM wholesale transactions, revenues increased faster than the related costs for fuel and purchased power. Higher electric generation sales resulted from additional sales to the wholesale market which benefited from increased internal generation. The improved generation margin occurred despite higher replacement power costs associated with the extended Davis-Besse outage (see Davis-Besse Restoration below). The gas margin decreased $9 million on falling sales.

Other factors contributing to the $48 million increase in income before interest and taxes include: o Lower nuclear production costs of $72 million primarily as a result of no nuclear refueling outages in the first quarter of 2004 compared to one refueling outage at Beaver Valley Unit 1 in last year's first quarter ($32 million) and reduced incremental maintenance costs at the Davis-Besse Plant ($35 million) related to its restart; o A net decrease of $19 million in other operating expenses as a result of reduced postretirement benefit plan expenses (see Postretirement Plans below) offset in part by additional severance costs and increased benefit costs for active employees; and 27 o Lower non-nuclear operating expenses primarily reflecting deferred planned outage work at FirstEnergy's fossil generating units ($10 million). Partially offsetting these lower costs were three factors: o Reduced revenues from distribution deliveries ($54 million); o Charges for depreciation and amortization that increased by $36 million primarily due to: higher charges resulting from increased amortization of the Ohio transition plan regulatory assets ($23 million), reduced shopping incentive deferrals under the Ohio transition plan ($4 million) and additional stranded cost amortization for Met-Ed and Penelec ($22 million). Partially offsetting these increases were reduced depreciation rates resulting from the JCP&L rate case ($11 million); and o Higher energy delivery costs of $10 million principally due to increased tree trimming activities and to a lesser extent JCP&L's accelerated reliability program. Income before discontinued operations and the cumulative effect of accounting changes increased $60 million from the comparable period last year. The change reflects reduced net interest charges of $34 million and increased income taxes of $22 million in addition to the changes discussed above. The decrease in interest expense is the result of debt and preferred stock redemptions and other financing activities. Proceeds from the issuance of 32.2 million shares of common stock in September 2003 accelerated the repayment of debt. Redemption and refinancing activities for debt and preferred stock aggregated approximately $653 million during the first quarter of 2004. The redemption and refinancing activities and pollution control note repricings are expected to result in annualized savings of $5 million. FirstEnergy also exchanged existing fixed-rate payments on outstanding debt (notional amount of $1.35 billion at March 31, 2004) for short-term variable rate payments through interest rate swap transactions (see Market Risk Information - Interest Rate Swap Agreements below). Net interest charges were reduced by $11$53 million in the first quarter of 2005 compared to the same period of 2004 as a result of a 0.4% increase in KWH sales and higher unit prices.Additional retail sales reduced energy available for sales to the wholesale market.

A decrease in reported segment revenues resulted from the following sources:

	Three Months Ended
Revenues	March 31,				Increase
By Type of Service	2005		2004		(Decrease)
	*(In millions)*

Electric Generation Sales:
Retail	$	980	$	934	$	46
Wholesale		295		288		7
Total Electric Generation Sales		1,275		1,222		53
Transmission		10		16		(6	)
Other		10		4		6
Total		1,295		1,242		53
PJM gross transactions		--		280		(280	)
Total Revenues	$	1,295	$	1,522	$	(227	)

Changes in KWH sales are summarized in the following table:

	Increase
Electric Generation	(Decrease)

Retail		1.2	%

Wholesale		(49.4	)%

Total Electric Generation		(15.9	)%*

*Increase of 0.4% excluding the effect of the PJM revision.

Expenses - -

Excluding the effect of the $280 million of PJM purchased power costs recorded on a gross basis in 2004, total operating expenses, net interest charges and income taxes increased by $87 million. The increase was due to the following factors:

·	Higher fuel and purchased power costs of $41 million, which include increased fuel costs of $34 million due to a greater reliance on higher cost fossil units during the nuclear refueling outages, and increased purchased power costs of $7 million;

Increased non-fuel nuclear costs of $66 million due primarily to a refueling outage at the Perry nuclear plant (including an unplanned extension), a scheduled 23-day mid-cycle inspection outage at the Davis-Besse nuclear plant in the first quarter of 2005 and the absence of nuclear scheduled outages in the same period last year;

·	Accrual of an $8.5 million civil penalty payable to the Department of Justice and $10 million for obligations to three states in connection with the Sammis Plant settlement;

·	Accrual of $3.5 million for a proposed NRC fine related to the 2002 Davis-Besse outage; and

·	Higher general taxes of $7 million due to additional gross receipts tax and payroll taxes.

Partially offsetting these ~~swaps. Discontinued Operations Net~~amounts were the following factors:

·	Lower transmission costs of $26 million due in part to an 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 $24 million due to lower taxable income.

Other - First Quarter 2005 Compared to First Quarter 2004

FirstEnergy’s financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a net improvement in FirstEnergy’s net income in the first quarter of ~~2003~~2005 compared to the same quarter of 2004. The improvement reflected the effect of discontinued operations, which included an after-tax ~~earnings~~net gain of $17 million from discontinued operations (see Note 6). The following table summarizes the sources of $2income from discontinued operations:

Other - First Quarter 2005 Compared to First Quarter 2004

	Three Months Ended
	March 31,
	2005		2004
	*(In millions)*
Discontinued Operations (Net of tax)
Gain on sale:
Natural gas business	$	5	$	--
Elliot-Lewis, Spectrum and Power Piping		12		--
Reclassification of operating income		2		1
Total	$	19	$	1

Postretirement Plans

Pension costs were lower due to last year’s $500 million ~~reflecting the reclassification of revenues~~voluntary contribution and expenses associated with divestitures of its Argentina and Bolivia international businesses and the FSG subsidiaries, Colonial Mechanical, Webb Technologies and Ancoma, Inc., as well as NEO. Cumulative Effect of Accounting Change Resultsan increase in the ~~first quarter~~market value of 2003 included an after-tax credit to net income of $102 million recorded upon the adoption of SFAS 143 in January 2003. FirstEnergy identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $602 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $415 million. The ARO liability at the date of adoption was $1.11 billion, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, FirstEnergy had recorded decommissioning liabilities of $1.24 billion. FirstEnergy expects substantially all of its nuclear decommissioning costs for Met-Ed, Penelec, JCP&L and Penn to be recoverable in rates over time. Therefore, FirstEnergy recognized a regulatory liability of $185 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning for those companies. The remaining cumulative effect adjustment for unrecognized depreciation and accretion offset by the reduction in the liabilities and the reversal of accumulated estimated removal costs for non-regulated generationpension plan assets ~~was a $175 million increase to income, or $102 million net of income taxes. Postretirement Plans Resurgent equity markets in 2003,~~during 2004. Combined with amendments to ~~FirstEnergy's~~FirstEnergy’s health care ~~benefits~~ plan in the first quarter of 2004, and the new Medicare Act signed by President Bush in December 2003 combined to reduce pensions and other postretirement costs -- despite continued increases in health care costs and projected trend rates. Combined, these employee benefit expenses decreased by ~~$26~~$20 million in the first quarter of ~~2004~~2005 compared to the same period in ~~2003.~~2004. The following table summarizes the net pension and OPEB expense (excluding amounts capitalized) for the three months ended March 31, ~~2004~~2005 and ~~2003. 28~~ Three Months Ended Postretirement Benefits Expense(1) March 31, ----------------------------------------------------- 2004 2003 ---- ---- (In millions) Pension...................... $20 $31 OPEB......................... 26 41 ----------------------------------------------------- Total...................... $46 $72 ===================================================== 2004.

	Three Months Ended
Postretirement Benefits Expense⁽¹⁾	March 31,
	2005		2004
	*(In millions*)

Pension	$	8	$	20
OPEB		18		26
Total	$	26	$	46

^(1).ExcludesExcludes the capitalized portion of postretirement benefits

costs (see Note 410 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. See "Critical Accounting Policies - Pension and Other Postretirement Benefits Accounting" for a discussion of the impact of underlying assumptions on postretirement expenses. Results of Operations - Business Segments FirstEnergy manages its business as two separate major business segments - regulated services and competitive services. In the first quarter of 2004, management made certain changes in presenting results for these two segments (see Note 8). The regulated services segment no longer includes a portion of generation services. 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. All generation services are now reported in the competitive services segment. As a result, its revenues include all generation electric sales revenues (including the generation services to regulated franchise customers who have not chosen an alternative generation supplier) and all domestic unregulated energy and energy-related services including commodity sales (both electricity and natural gas) in the retail and wholesale markets, marketing, generation, commodity sourcing and other competitive energy-application services such as heating, ventilating and air-conditioning. "Other" consists of interest expense related to holding company debt; corporate support services and the international businesses that were substantially divested by the first quarter of 2004. FirstEnergy's two major business segments include all or a portion of the following business entities: o The regulated services segment includes the regulated sale of electricity and distribution and transmission services by its eight electric utility operating companies in Ohio, Pennsylvania and New Jersey (OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec and ATSI) o The competitive services business segment consists of the subsidiaries (FES, FSG, MYR, MARBEL and FirstCom) that operate unregulated energy and energy-related businesses, including the operation of generation facilities of OE, CEI, TE and Penn resulting from the deregulation of the Companies' electric generation business (see Note 6 - Regulatory Matters). Financial results discussed below include revenues and expenses from transactions among FirstEnergy's business segments. A reconciliation of segment financial results to consolidated financial results is provided in Note 8 to the consolidated financial statements. Net income (loss) by business segment was as follows: Three Months Ended March 31, Net Income (Loss) --------------------- By Business Segment 2004 2003 ---------------------------------------------------- (In millions) Regulated services......... $ 216 $ 358 Competitive services....... -- (96) Other...................... (42) (44) ---------------------------------------------------- Total...................... $ 174 $ 218 ==================================================== Regulated Services - First Quarter 2004 versus First Quarter 2003 Financial results for the regulated services segment were as follows: Three Months Ended March 31, ------------------- Increase Regulated Services 2004 2003 (Decrease) - -------------------------------------------------------------------------------- (In millions) Total revenues............................... $1,295 $1,309 $ (14) Income before interest and income taxes....... 468 570 (102) Income before cumulative effect of accounting changes.................................... 216 257 (41) Net Income.................................... 216 358 (142) - -------------------------------------------------------------------------------- 29 The change in operating revenues resulted from the following sources: Three Months Ended March 31, --------------------- Increase Sources of Revenue Changes 2004 2003 (Decrease) ---------------------------------------------------------------------- (In millions) Electric sales............. $1,159 $1,213 $(54) Other sales................ 136 96 40 ---------------------------------------------------------------------- Total Sales................ $1,295 $1,309 $(14) ====================================================================== The decrease in electric revenues resulted from: o A net decrease of $54 million in retail sales -- a $58 million decrease in revenues from distribution deliveries partially offset by a $4 million decrease in shopping incentives to customers. o A net $40 million increase in other sales primarily due to higher transmission revenues. Lower revenues combined with increased expenses resulted in an $102 million decrease in income before interest and income taxes. Higher expenses included a $53 million increase in operating expenses from additional transmission expenses and energy delivery costs, as well as increased depreciation and amortization charges of $38 million. Competitive Services - First Quarter 2004 versus First Quarter 2003 Financial results for the competitive services segment were as follows: Three Months Ended March 31, ------------------ Increase Competitive Services 2004 2003 (Decrease) - -------------------------------------------------------------------------------- (In millions) Total revenues................................... $1,873 $1,874 $ (1) Income (Loss) before interest and income tax benefit 13 (146) 159 Income (Loss) before discontinued operations and cumulative effect of accounting changes....... -- (92) 92 Net income (loss)................................ -- (96) 96 - -------------------------------------------------------------------------------- The change in total revenues resulted from the following sources: Three Months Ended March 31, ------------------- Increase Sources of Revenue Changes 2004 2003 (Decrease) ---------------------------------------------------------------------- (In millions) Electric....................... $1,497 $1,411 $86 Natural Gas sales.............. 165 245 (80) Energy-related sales........... 178 187 (9) Other.......................... 33 31 2 ---------------------------------------------------------------------- Total Revenues................. $1,873 $1,874 $(1) ====================================================================== The increase in electric revenues resulted from: o Higher retail generation sales from sales through customer choice programs ($50 million) partially offset by lower generation sales from the EUOC ($27 million); and o Increased wholesale revenues of $160 million from FES (primarily into the spot market) offset in part by a $97 million decrease in EUOC sales to wholesale customers. Natural gas sales were $80 million lower primarily due to the expiration of customer choice programs in which FES participated and reduced sales to large industrial and commercial customers. Sales to large commercial and industrial customers declined reflecting fewer customers and more moderate temperatures than last year. The generation margin increased $53 million as electric generation revenues increased faster than the related costs for fuel and purchased power. Higher electric generation revenues resulted from additional sales to the wholesale market which benefited from increased internal generation. The improved generation margin occurred despite higher replacement power costs associated with the extended Davis-Besse outage (see Davis-Besse Restoration below). The margin on gas sales decreased $9 million on falling sales. Together with a higher net energy margin, reduced expenses contributed to a net $159 30 million increase in income before interest and income taxes. Major expense factors included the following: o Lower nuclear production costs of $72 million primarily as a result of no nuclear refueling outages in the first quarter of 2004 compared to one refueling outage at Beaver Valley Unit 1 in the first quarter last year ($32 million) and reduced incremental maintenance costs at the Davis-Besse Plant ($35 million) related to its restart. o A $10 million decrease in non-nuclear operating expenses primarily from deferred planned outage work at fossil generating units. o Reduced postretirement benefit plan expenses (see Postretirement Plans above) offset in part by increased benefit costs for active employees. Capital Resources and Liquidity FirstEnergy's

CAPITAL RESOURCES AND LIQUIDITY

FirstEnergy’s cash requirements in ~~2004~~2005 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing ~~FirstEnergy's~~FirstEnergy’s net debt and preferred stock outstanding. Available borrowing capacity under ~~short-term~~ credit facilities will be used to manage working capital requirements. ~~Over the next two years, FirstEnergy expects to meet its contractual obligations with cash from operations.~~ 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 ~~$1.25~~$1.375 billion of revolving credit facilities. In the first quarter of ~~2004,~~2005, FirstEnergy received ~~$124~~$137 million of cash dividends from its subsidiaries and paid ~~$122~~$135 million in cash ~~common stock~~ dividends to its common shareholders. There are no material restrictions on the ~~issuance~~payment of cash dividends by ~~FirstEnergy's~~FirstEnergy’s subsidiaries.

As of March 31, ~~2004,~~2005, FirstEnergy had ~~$280~~$81 million of cash and cash equivalents ($3 million restricted as an indemnity reserve) compared with ~~$114~~$53 million as of December 31, ~~2003.~~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 ~~competitive energy services~~power supply businesses (see ~~Results of Operations - Business Segments~~“RESULTS OF OPERATIONS” above). Net cash provided from operating activities was ~~$650~~$569 million in the first quarter of 2005 and $648 million in the first quarter of 2004, ~~and $462 million in the first quarter of 2003,~~ summarized as follows: Three Months Ended March 31, -------------------- Operating Cash Flows 2004 2003 ------------------------------------------------------------- (In millions)

	Three Months Ended
	March 31,
Operating Cash Flows	2005		2004
	*(In millions)*


Cash earnings⁽¹⁾	$	364	$	505
Working capital and other		205		143
Total Cash Flows from Operating Activities	$	569	$	648

⁽¹⁾Cash earnings ~~(1).................... $ 508 $ 363 Working capital~~are a non-GAAP measure (see reconciliation below).

Cash earnings (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 other............ 142 99 ------------------------------------------------------------- Total................................ $ 650 $ 462 ============================================================= (1)Includesmanagement with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash provided from operating activities increased $188income.

	Three Months Ended
	March 31,
Reconciliation of Cash Earnings	2005			2004
	*(In millions)*

Net Income (GAAP)	$	160		$	174
Non-Cash Charges (Credits):
Provision for depreciation		143			146
Amortization of regulatory assets		311			310
Deferral of new regulatory assets		(60	)		(44	)
Nuclear fuel and lease amortization		19			22
Deferred purchased power and other costs		(109	)		(84	)
Deferred income taxes and investment tax credits		(14	)		6
Deferred rents and lease market valuation liability		(36	)		(16	)
Income from discontinued operations		(19	)		(1	)
Other non-cash expenses		(31	)		(8	)
Cash Earnings (Non-GAAP)	$	364		$	505

The $141 million ~~due to a $145 million increase~~decrease in cash earnings ~~and a $43 million increase from changes in working capital.~~is described under "RESULTS OF OPERATIONS". The working capital increase primarily resulted from changes of $238 million in payables partially offset by a change ~~resulted primarily from the net proceeds from the settlement~~ of ~~FirstEnergy's claim against NRG, Inc. for the terminated sale of four power plants.~~ $182 million in receivables.

Cash Flows From Financing Activities ~~The following table provides details regarding security issuances and redemptions during~~

In the first ~~quarter~~quarters of 2005 and 2004, ~~and 2003: 31~~ Three Months Ended March 31, -------------------- Securities Issued or Redeemed 2004 2003 ---------------------------------------------------------------------- (In millions) New Issues Pollution control notes................... $112 $ -- Senior notes.............................. 317 250 Unsecured notes........................... 153 -- Long-term revolver........................ -- 50 Other, primarily debt discount............ -- (2) ----------------------------------------------------------------------- $582 $298 Redemptions First mortgage bonds...................... $92 $40 Pollution control notes................... -- 50 Secured notes............................. 42 108 Long-term revolving credit................ 135 -- Other, primarily redemption premiums...... -- 3 ----------------------------------------------------------------------- $269 $201 Short-term Borrowings, Net .................... $(388) $(237) ------------------------------------------------------------------------ Netnet cash ~~used for the above financing activities declined by $65 million in the first quarter of 2004 from the first quarter of 2003. The decrease in funds~~ used for financing activities ~~resulted from increased financing~~ of ~~$284~~$359 million ~~that exceeded $219~~and $240 million, respectively, primarily reflected the redemptions of ~~additional redemptions~~debt and ~~repayments during the first quarter of 2004 compared to the same period of 2003.~~ preferred stock shown below.

	Three Months Ended
	March 31,
Securities Issued or Redeemed	2005		2004
	*(In millions)*
New Issues
Pollution control notes	$	--	$	185
Senior notes		--		250
Unsecured notes		--		147
	$	--	$	582
Redemptions
First mortgage bonds	$	1	$	92
Secured notes		20		42
Long-term revolving credit		215		135
Preferred stock		98		--
	$	334	$	269

Short-term Borrowings, Net	$	140	$	(388	)

FirstEnergy had approximately ~~$134~~$310 million of short-term indebtedness as of March 31, ~~2004~~2005 compared to approximately ~~$522~~$170 million as of December 31, ~~2003.~~2004. Available bank borrowing capability as of March 31, ~~2004~~2005 included the following: FirstEnergy Borrowing Capability Holding Company OE Total - ---------------------------------------------------------------------------- (In millions) Long-Term Revolver................ $ 875 $375 $1,250 Utilized.......................... (175) -- (175) Letters of Credit................. (183) -- (183) - ---------------------------------------------------------------------------- Net............................... 517 375 892 - ---------------------------------------------------------------------------- Short-Term Facilities: Revolver.......................... 375 125 500 Bank ............................. -- 34 34 - ---------------------------------------------------------------------------- ................................... 375 159 534 - ---------------------------------------------------------------------------- Utilized: Revolver.......................... -- -- -- Bank.............................. -- -- -- - ---------------------------------------------------------------------------- Net............................... 375 159 534 - ---------------------------------------------------------------------------- Amount Available.................. $ 892 $534 $1,426 ============================================================================

Borrowing Capability	FirstEnergy			OE		Penelec			Total
	(In millions)
Long-term revolving credit	$	1,375		$	375	$	--		$	1,750
Utilized		--			--		--			--
Letters of credit		(141	)		--		--			(141	)
Net		1,234			375		--			1,609

Short-term bank facilities		--			34		100			134
Utilized		--			--		(100	)		(100	)
Net		--			34		--			34
Total Unused Borrowing Capability	$	1,234		$	409	$	--		$	1,643

As of March 31, ~~2004,~~2005, the Ohio ~~companies~~Companies and Penn had the aggregate capability to issue approximately ~~$3.2~~$4.3 billion of additional ~~first mortgage bonds (FMB)~~FMB on the basis of property additions and retired bonds ~~although unsecured senior note indentures entered into~~under the terms of their respective mortgage indentures. The issuance of FMB by OE and CEI ~~in 2004 limit each company's ability to issue secured debt, including FMBs,~~are also subject to ~~certain exceptions. JCP&L, Met-Ed and Penelec no longer issue FMB other than (in the case~~provisions of ~~JCP&L and Penelec) as collateral for senior notes, since~~ their senior note indentures ~~prohibit them (subject~~generally limiting the incurrence of additional secured debt, subject to certain ~~exceptions) from issuing any~~exceptions that would permit, among other things, the issuance of secured debt ~~which is senior~~(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 ~~the senior notes. As~~incur additional secured debt not otherwise permitted by a specified exception of up to $650 million and $565 million, respectively, as of March 31, ~~2004, JCP&L and Penelec had the aggregate capability to issue $545 million of additional senior notes using FMB collateral. Because Met-Ed satisfied~~2005. Under the provisions of its senior note indenture, ~~for the release of all FMBs held~~JCP&L may issue additional FMB only as collateral for senior ~~notes in~~notes. As of March ~~2004, it is no longer required~~31, 2005, JCP&L had the capability to issue ~~FMBs as collateral for future issuances~~$578 million of additional senior notes ~~and therefore not limited as to~~upon the ~~amount~~basis of ~~senior notes it may issue.~~FMB collateral. Based upon applicable earnings coverage tests in their respective charters, OE, Penn, TE and JCP&L could issue a total of ~~$3.4~~$4.0 billion of preferred stock (assuming no additional debt was issued) as of March 31, ~~2004.~~2005. CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred stock. ~~In October~~

As of March 31, 2005, approximately $1.0 billion remained under FirstEnergy's shelf registration statement, filed with the SEC in 2003, ~~FirstEnergy restructured its~~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 syndicated $1 billion ~~364-day~~three-year revolving credit facility ~~through a~~maturing in June 2007. Combined with FirstEnergy’s syndicated ~~bank offering that was completed on October 23, 2003. The new syndicated FirstEnergy facilities consist of a $375 million 364-day revolving credit facility and a~~ $375 million three-year ~~revolving credit facility. Also on~~facility maturing in October ~~23, 2003, OE entered into~~2006, a ~~syndicated~~ $125 ~~million 364-day revolving credit facility and a syndicated $125 million three-year revolving credit facility. Combined with an existing syndicated $500~~ million three-year facility for ~~FirstEnergy,~~OE maturing in ~~November 2004,~~October 2006, and ~~an existing~~a syndicated $250 million two-year facility for OE 32 maturing in May 2005, ~~FirstEnergy's~~ primary syndicated credit facilities total $1.75 billion. These revolving credit facilities, 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 ~~the~~ short-term working capital requirements ~~of FE~~for FirstEnergy and its subsidiaries. ~~Available~~Total unused borrowing ~~capacity~~capability under existing facilities and accounts receivable financing facilities totaled ~~$1.426~~$1.9 billion as of March 31, ~~2004.~~ 2005.

Borrowings under these facilities are conditioned on ~~FirstEnergy and/or OE~~ maintaining compliance with certain financial covenants in the agreements. FirstEnergy ~~under its $375 million 364-day and $375 million three-year facilities,~~ and OE ~~under its $125 million 364-day and $250 million two-year facilities,~~ are each required to maintain a debt to total capitalization ratio of no more than 0.65 to 1 and a ~~contractually-defined~~contractually defined fixed charge coverage ratio of no less than 2 to 1. ~~Under its $500 million three-year facility, FirstEnergy is required~~As of March 31, 2005, FirstEnergy’s and OE’s fixed charge coverage ratios, as defined under the credit agreements, were 4.47 to ~~maintain a~~1 and 6.87 to 1, respectively. FirstEnergy's and OE's debt to total capitalization ~~ratio of no more than 0.69~~ratios, as defined under the credit agreements, were 0.55 to 1 and ~~a contractually-defined fixed charge coverage ratio for the most recent fiscal quarter of no less than 1.5~~0.40 to ~~1. FirstEnergy and OE are in compliance with all of these financial covenants.~~1, respectively. The ability to draw on each of these facilities is also conditioned upon FirstEnergy or OE making certain representations and warranties to the lending banks prior to drawing on their respective facilities, including a representation that there has been no material adverse change in ~~its~~their business, ~~its~~ condition (financial or otherwise), ~~its~~ results of operations, or ~~its~~ prospects. ~~None of~~

Neither FirstEnergy's ~~or OE's~~nor OE’s primary credit facilities contain any provisions ~~whereby~~that either restrict their ability to borrow ~~would be restricted~~ or ~~denied, or~~accelerate repayment of outstanding ~~loans under the facilities accelerated,~~advances as a result of any change in ~~the~~their credit ~~ratings of FirstEnergy or OE by any of the nationally-recognized rating agencies. Borrowings under each of the~~ratings. Each primary ~~facilities do~~facility does contain "pricing grids", whereby the cost of funds borrowed under the ~~facilities~~facility is related to the credit ratings of the company borrowing the funds. ~~FirstEnergy's~~

FirstEnergy’s regulated companies 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 ~~its competitive~~FirstEnergy’s unregulated companies. ~~FirstEnergy Service Company~~FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and ~~competitive~~unregulated subsidiaries, as well as proceeds available from bank borrowings. For the regulated companies, available bank borrowings include $1.75 billion from ~~FirstEnergy's~~FirstEnergy and ~~OE's~~OE’s revolving credit facilities. For the ~~competitive~~unregulated companies, available bank borrowings include only ~~the $1.25~~FirstEnergy’s $1.375 billion of ~~FirstEnergy's~~ revolving credit ~~facility.~~facilities. Companies receiving a loan under the money pool agreements must repay the principal amount of ~~such a~~the loan, together with accrued interest, within 364 days of borrowing the funds. ~~For the regulated and competitive money pools, the~~The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first quarter of ~~2004~~2005 was ~~1.30%~~2.66% for the regulated ~~companies'~~companies’ money pool and ~~1.57%~~2.68% for the ~~competitive~~unregulated companies' money pool. In January and March of 2004, FirstEnergy executed four fixed-to-floating interest rate swap agreements with notional amounts of $50 million each on underlying EUOC senior notes and subordinated debentures with an average fixed rate of 5.73%. In March 2004, Met-Ed, Penelec and Penn completed on-balance sheet, receivable financing transactions which allow each company to borrow up to $80 million, $75 million and $25 million, respectively. The borrowing rates are based on bank commercial paper rates. Met-Ed and Penelec are required to pay annual facility fees of 0.30% on the entire finance limit. Penn Power is required to pay an annual facility fee of 0.40% on the entire finance limit. The facilities were undrawn at the end of March 2004. These facilities mature on March 29, 2005.

On March 25, 2004, Met-Ed issued $250 million principal amount of 4.875% Senior Notes due 2014. A portion of the proceeds were used to redeem $50 million aggregate principal amount of outstanding Met-Ed Medium Term Notes (MTNs) having a weighted average interest cost of 6.39%, and to pay down short-term debt. Met-Ed also intends to use a portion of the proceeds to redeem $100 million principal amount of Met-Ed Capital Trust's 7.35% Trust Preferred Securities in the second quarter of 2004 and to pay at maturity $40 million principal amount of Met-Ed's 6.34% MTNs maturing August 27, 2004. On March 31, 2004, Penelec issued $150 million principal amount of 5.125% Senior Notes due 2014. The proceeds of this transaction were used to redeem $125 million principal amount of 5.75% Senior Notes that matured on April 1, 2004 and to repay short-term debt. On April 23, 2004, JCP&L issued $300 million of 5.625% Senior Notes due 2016. The proceeds of this transaction will be used to redeem $40 million of 7.98% JCP&L Series C MTNs due 2023 and $50 million of 6.78% JCP&L Series C MTNs due 2005. The remaining proceeds will be used to fund the mandatory redemption of JCPL's $160 million of 7.125% FMB due October 1, 2004 and to reduce short-term debt. On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2 from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that the lower ratings were prompted by: "1) high consolidated leverage with significant holding company debt, 2) a degree of regulatory uncertainty in the 33 service territories in which the company operates, 3) risks associated with investigations of the causes of the August 2003 blackout, and related securities litigation, and 4) a narrowing of the ratings range for the FirstEnergy operating utilities, given the degree to which FirstEnergy increasingly manages the utilities as a single system and the significant financial interrelationship among the subsidiaries." On March 9, 2004,18, 2005, S&P stated that ~~the NRC's permission~~FirstEnergy’s Sammis NSR settlement was a very favorable step for FirstEnergy, although it would not immediately affect FirstEnergy’s ratings or outlook. S&P noted that it continues to ~~restart~~monitor the ~~Davis-Besse~~refueling outage at the Perry nuclear plant, ~~was positive for credit quality because it~~which includes a detailed inspection by the NRC, and that if FirstEnergy should exit the outage without significant negative findings or delays the ratings outlook would ~~positively affect cash flow by eliminating replacement power costs~~be revised to positive.

On March 14, 2005, CEI redeemed all 500,000 outstanding shares of its Serial Preferred Stock, $7.40 Series A at a price of $101 per share plus accrued dividends to the date of the redemption. Also on March 14, 2005, CEI redeemed all 474,000 outstanding shares of its Serial Preferred Stock, Adjustable Rate Series L at a price of $100 per share plus accrued dividends to the date of the redemption.

On May 16, 2005, Penn intends to redeem all 127,500 outstanding shares of 7.625% preferred stock at $102.29 per share and ~~"demonstrating management's ability~~all 250,000 outstanding shares of 7.75% preferred stock at $100 per share, both plus accrued dividends to overcome operational challenges." However, S&P did not change FirstEnergy's ratings or outlook because it stated that financial performance still "significantly lags expectations and management faces other operational hurdles." the date of redemption.

On June 1, 2005, CEI intends to redeem all of its 40,000 outstanding shares of $7.35 Series C preferred stock at $101.00 per share, plus accrued dividends to the date of redemption.

Cash Flows From Investing Activities

Net cash flows used ~~for~~in investing activities ~~totaled $243 million in~~resulted principally from property additions. Regulated services expenditures for property additions primarily include expenditures supporting the ~~first quarter~~distribution of ~~2004, compared to net cash flows of $118 million used for investing activities for~~electricity. Capital expenditures by the same period of 2003. The $125 million change primarily resulted from a refunding payment of $51 million to a NUG trust fund in the first quarter 2004 compared to $106 million of withdrawals in the first quarter of 2003.power supply management services segment are principally generation-related. The following table summarizes first quarter 2005 and 2004 investments by ~~FirstEnergy's~~FirstEnergy’s regulated services, power supply management services and ~~competitive services~~other segments: ~~Summary~~

Summary of Cash Flows	Property
Used for Investing Activities	Additions			Investments			Other			Total
2005 First Quarter Sources (Uses)	*(In millions)*

Regulated services	$	(141	)	$	23		$	3		$	(115	)
Power supply management services		(81	)		(1	)		--			(82	)
Other		(3	)		16			(13	)		--
Reconciling items		(4	)		20			--			16
Total	$	(229	)	$	58		$	(10	)	$	(181	)

2004 First Quarter Sources (Uses)
Regulated services	$	(91	)	$	(49	)	$	(2	)	$	(142	)
Power supply management services		(44	)		(1	)		--			(45	)
Other		(1	)		(7	)		2			(6	)
Reconciling items		(2	)		(27	)		(20	)		(49	)
Total	$	(138	)	$	(84	)	$	(20	)	$	(242	)

Net cash used for investing activities in the first quarter of First Quarter 2004 Property Cash Used for Investing Activities Additions Investments Other Total - -------------------------------------------------------------------------------- Sources (Uses) (In millions) Regulated Services.................... $ (90) $(79)(1) $ (2) $(171) Competitive Services.................. (45) 20 2 (23) Other................................. (3) (26) (20) (49) - -------------------------------------------------------------------------------- Total............................ $(138) $(85) $(20) $(243) ================================================================================ (1) Includes2005 was $61 million lower compared with the same period of 2004. The decrease was primarily due to higher proceeds of $42 million from assets sales (see Note 6 to the consolidated financial statements), the absence of a $51 million ~~refunding payment to a~~ NUG trust ~~fund.~~ contribution in 2004 and increased other investment earnings, partially offset by a $91 million increase in property additions.

During the remaining three quarters of ~~2004,~~2005, capital requirements for property additions and capital leases are expected to be approximately ~~$666~~$825 million, including ~~$86~~$20 million for nuclear fuel. FirstEnergy has additional requirements of approximately ~~$902~~$172 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of ~~2004.~~2005. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. ~~FirstEnergy's current forecast reflects expenditures of approximately $2.3~~

FirstEnergy’s capital spending for the period 2005-2007 is expected to be about $3.3 billion ~~for property additions and improvements from 2004-2006,~~(excluding nuclear fuel), of which ~~approximately $720~~$998 million ~~is applicable~~applies to ~~2004.~~2005. Investments for additional nuclear fuel during the ~~2004-2006~~2005-2007 period are estimated to be approximately ~~$315~~$274 million, of which approximately ~~$86~~$53 million applies to ~~2004.~~2005. During the same ~~periods, the Companies'~~period, FirstEnergy’s nuclear fuel investments are expected to be reduced by approximately ~~$281~~$280 million and ~~$91~~$86 million respectively, as the nuclear fuel is consumed. As of March 31, 2004, FirstEnergy had $278 million in deposits pledged as collateral to secure reimbursement obligations related to certain letters of credit supporting OE's obligations to lessors under the Beaver Valley Unit 2 sale and leaseback arrangements. The deposits had previously been classified as a noncurrent investment. OE expects to replace the cash collateralized LOC with a structure that would not require cash collateral. OE anticipates using the cash from the deposit to repay short term debt in the third quarter of 2004 and for other general corporate purposes.

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 ~~letters~~LOCs. Some of ~~credit.~~ the guaranteed contracts contain ratings contingent collateralization provisions.

As of March 31, ~~2004,~~2005, the maximum potential future payments under outstanding guarantees and other assurances totaled ~~$1.9~~$2.4 billion as summarized below: 34 Maximum Guarantees and Other Assurances Exposure ------------------------------------------------------------ (In millions) FirstEnergy Guarantees of Subsidiaries: Energy and Energy-Related Contracts(1)...... $ 862 Other (2)................................... 149 -------------------------------------------------------- 1,011 Surety Bonds.................................. 240 Letters of Credit (3)(4)...................... 677 -------------------------------------------------------- Total Guarantees and Other Assurances....... $ 1,928 ========================================================== (1) Issued for a one-year term, with a 10-day termination right by FirstEnergy. (2) Issued for various terms. (3) Includes letters of credit of $183 million issued for various terms under letter of credit capacity available in FirstEnergy's revolving credit agreement. (4) Includes unsecured letters of credit of approximately $216 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by CEI and TE, as well as collateralized letters of credit of $278 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE.

	Maximum
Guarantees and Other Assurances	Exposure
	*(In millions)*

FirstEnergy Guarantees of Subsidiaries:
Energy and Energy-Related Contracts⁽¹⁾	$	909
Other⁽²⁾		149
		1,058

Surety Bonds		267
Letters of Credit⁽³⁾⁽⁴⁾		1,059

Total Guarantees and Other Assurances	$	2,384

⁽¹⁾

Issued for a one-year term, with a 10-day termination right by FirstEnergy.

⁽²⁾

Issued for various terms.

⁽³⁾

Includes $141 million issued for various terms under LOC capacity available under

FirstEnergy’srevolving credit agreement and $299 million outstanding in support

of pollution control revenue bondsissued with various maturities.

⁽⁴⁾

Includes approximately $194 million pledged in connection with the sale and

leaseback of Beaver ValleyUnit 2 by CEI and TE, $291 million pledged in connection

with the sale and leaseback of Beaver Valley Unit 2by 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'~~counterparties’ claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, ~~FirstEnergy's~~FirstEnergy’s guarantee enables the ~~counterparty's~~counterparty’s legal claim to be satisfied by ~~FirstEnergy's~~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 ~~activities~~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~~“material adverse ~~event"~~event” the immediate ~~payment~~posting of cash collateral or provision of an LOC may be ~~required.~~required of the subsidiary. The following table summarizes collateral provisions in effect as of March 31, 2004: Collateral Paid Total ----------------------- Remaining Collateral Provisions Exposure Cash Letters of Credit Exposure (1) - -------------------------------------------------------------------------------- (In millions) Rating downgrade............ $228 $133 $18 $ 77 Adverse event............... 232 -- 69 163 - -------------------------------------------------------------------------------- Total....................... $460 $133 $87 $240 ================================================================================ (1) As of April 12, 2004, FirstEnergy's remaining exposure was $237 million, with $141 million of cash and $72 million of letters of credit provided as collateral. 2005:

	Total		Collateral Paid				Remaining
Collateral Provisions	Exposure		Cash		LOC		Exposure⁽¹⁾
	*(In millions)*

Credit rating downgrade	$	364	$	153	$	18	$	193
Adverse event		42		--		8		34
Total	$	406	$	153	$	26	$	227

(1)

As of May 2, 2005, FirstEnergy’s total exposure decreased to $357 million and the remaining exposure decreased to

$183 million - net of $148 million of cash collateral and $26 million of LOC collateral provided to counterparties.

Most of ~~FirstEnergy's~~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. Various contracts include credit enhancements in the form of cash collateral, letters of credit or other security in the event of a reduction in credit rating. Requirements of these provisions vary and typically require more than one rating reduction to below investment grade by S&P or Moody's to trigger additional collateralization.

FirstEnergy has ~~also~~ guaranteed the obligations of the operators of the TEBSA project ~~in Colombia,~~ 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 ~~the TEBSA project lenders a $60 million~~an LOC (currently at $47 million), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA. ~~This LOC granted FirstEnergy the ability to sell its remaining 20.1% interest in Avon.~~

OFF-BALANCE SHEET ARRANGEMENTS

FirstEnergy has obligations that are not included on its Consolidated Balance ~~Sheets~~Sheet related to the sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are reflected as part of the operating lease payments. The present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.4 billion as of March 31, ~~2004.~~ 2005.

CEI and TE sell substantially all of their retail customer receivables to CFC, a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust (a "qualified special purpose entity" under SFAS 140) under an asset-backed securitization agreement. This arrangement provided ~~$200~~$142 million of off-balance sheet financing as of March 31, 2004. As of March 31, 2004, off-balance sheet arrangements include certain statutory business trusts created by CEI, Met-Ed and Penelec to issue trust preferred securities aggregating $285 million. These trusts were included in the consolidated financial statements of FirstEnergy prior to the adoption of FIN 46R, but have subsequently been deconsolidated under FIN 46R (see Note 7 - New Accounting Standards and Interpretations). This deconsolidation has not resulted in any change in outstanding debt. 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.

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~~FirstEnergy’s Risk Policy Committee, comprised of ~~executive officers, exercises an independent risk~~members of senior management, provides general management oversight ~~function~~ to ~~ensure compliance with corporate~~ risk management ~~policies and prudent risk management practices.~~ activities throughout the Company.

Commodity Price Risk

FirstEnergy is exposed to market risk primarily due to fluctuating electricity, natural gas, coal, nuclear fuel and emission allowance prices. 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 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.Most of ~~FirstEnergy's~~FirstEnergy’s non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. The change in the fair value of commodity derivative contracts related to energy production during the first quarter of ~~2004~~2005 is summarized in the following table: 36

Increase (Decrease) in the Fair Value of Commodity Derivative Contracts
	Non-Hedge			Hedge			Total
	*(In millions)*

Change in the Fair Value of Commodity Derivative Contracts:
Outstanding net asset as of January 1, 2005	$	62		$	2		$	64
New contract value when entered		--			--			--
Additions/change in value of existing contracts		(1	)		6			5
Change in techniques/assumptions		--			--			--
Settled contracts		(7	)		1			(6	)
Sale of retail natural gas contracts		1			(6	)		(5	)

Outstanding net asset as of March 31, 2005⁽¹⁾	$	55		$	3		$	58

Non-commodity Net Assets as of March 31, 2005:
Interest Rate Swaps⁽²⁾		--			(27	)		(27	)
Net Assets - Derivatives Contracts as of March 31, 2005	$	55		$	(24	)	$	31

Impact of Changes in Commodity Derivative Contracts:⁽³⁾
Income Statement Effects (Pre-Tax)	$	--		$	--		$	--
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax)	$	--		$	1		$	1
Regulatory Liability	$	(7	)	$	--		$	(7	)

⁽¹⁾Includes ~~$59~~$54 million in non-hedge commodity derivative contracts which are offset by a regulatory liability.

⁽²⁾Interest rate swaps are treated as fair value hedges. Changes in derivative values are offset by changes in the hedged debts' premium or ~~discount.~~

discount (see Interest Rate Swap Agreements below).

^{(3) Excludes $24 million of derivative contract fair value decrease, as of
March 31, 2004, representing FirstEnergy's 50% share of Great Lakes
Energy Partners, LLC.
(4)}Represents the ~~increase~~change in value of existing contracts, settled contracts and changes in techniques/assumptions.

Derivatives are included on the Consolidated Balance Sheet as of March 31, ~~2004~~2005 as follows: Balance Sheet Classification Non-Hedge Hedge Total ----------------------------------------------------------------------- (In millions) Current- Other Assets...................... $ 10 $11 $ 21 Other Liabilities................. (6) -- (6) Non-current- Other Deferred Charges............ 60 44 104 Other Noncurrent Liabilities...... -- (5) (5) ---------------------------------------------------------------------- Net assets........................ $ 64 $50 $ 114 ======================================================================

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

Non-Current-
Other deferred charges		56			2			58
Other noncurrent liabilities		--			(28	)		(28	)

Net assets	$	55		$	(24	)	$	31

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:

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

Prices actively quoted⁽²⁾	$	5		$	2		$	1	$	--	$	--	$	--	$	8
Sale of retail natural gas contracts⁽²⁾		(4	)		(1	)		--		--		--	��	--		(5	)
Other external sources⁽³⁾		11			10			--		--		--		--		21
Prices based on models		--			--			10		9		7		8		34

Total⁽⁴⁾	$	12		$	11		$	11	$	9	$	7	$	8	$	58

⁽¹⁾For the last three quarters of ~~2004.~~ 2005.

⁽²⁾Exchange traded.

⁽³⁾Broker quote sheets.

⁽⁴⁾Includes ~~$59~~$54 million in non-hedge commodity derivative contracts which are offset by a regulatory liability. 37

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 March 31, ~~2004.~~2005. Based on derivative contracts held as of March 31, ~~2004,~~2005, an adverse 10% change in commodity prices would decrease net income by approximately $1 million for the next twelve months.

Interest Rate Swap Agreements ~~During the first quarter of 2004,~~

FirstEnergy ~~entered into~~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 a fixed-rate, long-term debt ~~issues -~~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. ~~As a result of the differences between fixed and variable debt rates, interest expense was $11 million lower in~~During the first quarter of ~~2004.~~2005, FirstEnergy executed two new interest rate swaps with a notional amount of $50 million each ($100 million total notional amount) on underlying EUOC and FirstEnergy senior notes with an average fixed rate of 6.51%. As of March 31, ~~2004,~~2005, the debt underlying the $1.75 billion outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of ~~5.44%~~5.59%, which the swaps have effectively converted to a current weighted average variable interest rate of ~~2.11%~~4.32%. ~~Interest Rate Swaps~~

~~(1) FirstEnergy no longer had the cash flow hedges as of January 30, 2004 as a result of the divestiture of Los Amigos Leasing Company, Ltd.. - a subsidiary of GPU Power.~~

Interest Rate Swaps

	March 31, 2005							December 31, 2004
	Notional		Maturity		Fair			Notional		Maturity		Fair
Denomination	Amount		Date		Value			Amount		Date		Value
	*(Dollars in millions)*
Fixed to Floating Rate
(Fair value hedges)	$	200		2006	$	(3	)	$	200		2006	$	(1	)
		100		2008		(3	)		100		2008		(1	)
		100		2010		(2	)		100		2010		1
		100		2011		--			100		2011		2
		450		2013		(7	)		400		2013		4
		100		2014		--			100		2014		2
		150		2015		(9	)		150		2015		(7	)
		200		2016		(2	)		200		2016		1
		150		2018		3			150		2018		5
		50		2019		2			50		2019		2
		150		2031		(6	)		100		2031		(4	)
	$	1,750			$	(27	)	$	1,650			$	4

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately ~~$821~~$956 million and ~~$779~~$951 million as of March 31, ~~2004~~2005 and December 31, ~~2003,~~2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in ~~an $82~~a $96 million reduction in fair value as of March 31, ~~2004.~~ 2005.

CREDIT RISK

Credit risk is the risk of an ~~obligor's~~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 ~~stringent~~ 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 ~~S&P~~ rating for energy contract counterparties of ~~"BBB."~~BBB (S&P). As of March 31, ~~2004~~2005, the largest credit concentration ~~to any counterparty~~ was ~~8% - which is a~~with one party, currently rated investment grade, ~~counterparty. Outlook Business Organization~~that represented 7% of FirstEnergy's ~~business is managed~~total credit risk. Within its unregulated energy subsidiaries, 99% of credit exposures, net of collateral and reserve, were with investment-grade counterparties as two distinct operating segments - a competitive services segment and a regulated services segment. FES provides competitive retail energy services while the EUOC provide regulated transmission and distribution services. FGCO, a wholly owned subsidiary of FES, leases fossil and hydroelectric plants from the EUOC and operates those plants. FirstEnergy expects the transfer of ownership of EUOC nonnuclear generating assets to FGCO 38 will be substantially completed by the end of the Ohio market development period. All of the EUOC power supply requirements for the Ohio Companies and Penn are provided by FES to satisfy their PLR obligations, as well as grandfathered wholesale contracts.March 31, 2005.

Outlook

State Regulatory Matters

In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry ~~deregulation included~~restructuring contain similar provisions ~~which~~that are reflected in the ~~EUOC's~~Companies' respective state regulatory plans. ~~However, despite these similarities, the specific approach taken by each state and for each of the EUOCs varies. Those~~These provisions include: ~~o allowing~~

·	restructuring the ~~EUOC's~~ electric generation business and allowing the Companies' customers to select their generation suppliers; o establishing PLR obligations to customers in the EUOC's service areas; o allowing recovery of transition costs (sometimes referred 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 EUOC recognize, as stranded investment) not otherwise recoverable in a competitive generation market; o itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and transition costs recovery charges; o deregulating the electric generation businesses; o continuing regulation of the EUOC's transmission and distribution systems; and o requiring corporate separation of regulated and unregulated business activities. Regulatoryregulatory assets, ~~are~~ costs which the ~~respective regulatory agencies~~FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods ~~and, without~~or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income ~~when~~as incurred. All ~~of the~~ regulatory assets are expected to ~~continue to~~ be recovered from customers under the ~~provisions of 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.

Regulatory Assets*	March 31,		December 31,		Increase
	2005		2004		(Decrease)
	*(In millions)*
OE	$	1,022	$	1,116	$	(94	)
CEI		925		959		(34	)
TE		349		375		(26	)
JCP&L		2,268		2,176		92
Met-Ed		750		693		57
Penelec		278		200		78
ATSI		14		13		1
Total	$	5,606	$	5,532	$	74

*Penn had net regulatory liabilities of approximately $27 million and $18 million included in Noncurrent

Liabilities on the Consolidated Balance Sheet as ~~discussed below. The regulatory assets~~ of ~~the individual companies are as follows:~~ March 31, 2005 and December 31, ~~Regulatory Assets~~ 2004, 2003 (Decrease) ---------------------------------------------------------------------------- (In millions) OE............................ $1,348 $1,451 $ (103) CEI........................... 1,022 1,056 (34) TE............................ 432 459 (27) Penn.......................... 15 28 (13) JCP&L......................... 2,457 2,558 (101) Met-Ed........................ 990 1,028 (38) Penelec....................... 459 497 (38) --------------------------------------------------------------------------- Total......................... $6,723 $7,077 $(354) =========================================================================== respectively.

Regulatory assets by source are as follows:

Regulatory Assets By Source	March 31,			December 31,			Increase
	2005			2004			(Decrease)
	*(In millions)*
Regulatory transition costs	$	4,881		$	4,889		$	(8	)
Customer shopping incentives*		668			612			56
Customer receivables for future income taxes		296			246			50
Societal benefits charge		40			51			(11	)
Loss on reacquired debt		87			89			(2	)
Employee postretirement benefits costs		62			65			(3	)
Nuclear decommissioning, decontamination
and spent fuel disposal costs		(163	)		(169	)		6
Asset removal costs		(345	)		(340	)		(5	)
Property losses and unrecovered plant costs		45			50			(5	)
Other		35			39			(4	)
Total	$	5,606		$	5,532		$	74

*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 $668 million as

of March 31, December 31, Increase Regulatory Assets By Source 2004 2003 (Decrease) ----------------------------------------------------------------------------- (In millions) Regulatory2005 (OE - $250 million, CEI - $320 million, TE - $98 million) will be recovered through a surcharge

rate equal to the RTC rate in effect when the transition ~~charge............. $6,088 $6,427 $(339) Customer shopping incentives............. 413 371 42 Customer receivables~~costs have been fully recovered. Recovery of the new

regulatory assets will begin at that time and amortization of the regulatory assets for future income taxes 315 340 (25) Societal benefits charge................. 81 81 -- Loss on reacquired debt.................. 74 75 (1) Postretirement benefits.................. 74 77 (3) Nuclear decommissioning, decontamination and spent fuel disposal costs.......... (106) (96) (10) Component removal costs.................. (327) (321) (6) Property losses and unrecovered plant costs 65 70 (5) Other.................................... 46 53 (7) --------------------------------------------------------------------------- Total.................................... $6,723 $7,077 $(354) =========================================================================== 39 each accounting period

will be equal to the surcharge revenue recognized during that period.

Reliability Initiatives ~~On October 15, 2003, NERC issued a Near Term Action Plan that contained recommendations for all control areas and reliability coordinators~~

FirstEnergy is proceeding with ~~respect to enhancing system reliability. Approximately 20~~the implementation of the recommendations ~~were directed at the FirstEnergy companies and broadly focused on initiatives~~regarding enhancements to regional reliability that are recommended for completion by summer 2004. These initiatives principally relate to changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and, preparedness and operating center training. FirstEnergy presented a detailed compliance plan to NERC, which NERC subsequently endorsed on May 7, 2004, and the various initiatives are expectedwere to be completed ~~no later than June 30, 2004. On February 26-27,~~subsequent to 2004 ~~certain FirstEnergy companies participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC~~and will continue to ~~review control area operations throughout much of~~periodically assess the United States during 2004, is an independent review to identify areas for improvement. The final audit report was completed on April 30, 2004. The report identified positive observations and included variousFERC-ordered Reliability Study recommendations for ~~improvement. FirstEnergy is currently reviewing~~forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the ~~audit results and recommendations and expects to implement those relating to summer 2004 by June 30. Based on its review thus~~recommendations. Thus far, ~~FirstEnergy believes that none~~implementation of the recommendations ~~identify a need for any incremental~~has not required, nor is expected to require, substantial investment in new, or material investment or upgrades to existing equipment. FirstEnergy notes, however, that NERC 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. On March 1, 2004, certain FirstEnergy companies filed, in accordance with a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. - Canada Power System Outage Task Force interim report. In particular, the filing addressed upgrades to FirstEnergy's control room computer hardware and software and enhancements to the training of control room operators. The PUCO will review the plan before determining the next steps, if any, in the proceeding. On April 22, 2004, FirstEnergy filed with FERC the results of the FERC-ordered independent study of part of Ohio's power grid. The study examined, among other things, the reliability of the transmission grid in critical points in the Northern Ohio area and the need, if any, for reactive power reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing the results of that study and expects to complete the implementation of recommendations relating to 2004 by this summer. Based on its review thus far, FirstEnergy believes that the study does not recommend any incremental material investment or upgrades, to existing equipment. 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. ~~With respect~~Finally, the PUCO is continuing to ~~each~~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 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 ~~foregoing initiatives, FirstEnergy has requested~~final report of a focused audit of JCP&L's Planning and ~~NERC has agreed to provide, a technical assistance team of experts to provide ongoing guidance~~Operations and ~~assistance in implementing~~Maintenance programs and confirming timely and successful completion. Ohio FirstEnergy's transition plan for the Ohio EUOC included approval for recovery of transition costs, including regulatory assets, through no later than 2006 for OE, mid-2007 for TE and 2008 for CEI, except where a longer period of recovery is provided forpractices (Focused Audit). A Final Order in the ~~settlement agreement; granting preferred access over its subsidiaries~~Focused Audit docket was issued by the NJBPU on July 23, 2004. On February 11, 2005, JCP&L met with the Ratepayer Advocate to ~~nonaffiliated marketers, brokers~~discuss reliability improvements. JCP&L continues to file compliance reports reflecting activities associated with the MOU and ~~aggregators, to 1,120 MW of generation capacity through 2005 at established prices for sales~~Stipulation.

See Note 13 to the ~~Ohio EUOC's retail customers;~~consolidated financial statements for a more detailed discussion of reliability initiatives, including actions by the PPUC, that impact Met-Ed, Penelec and freezing customer prices through a five-year market development period (2001-2005), except for certain limited statutory exceptions including a 5% reduction in the price of generation for residential customers. In February 2003, the Penn.

Ohio EUOC were authorized increases in revenues aggregating approximately $50 million (OE - $41 million, CEI - $4 million and TE - $5 million) to recover their higher tax costs resulting from the Ohio deregulation legislation.

The Ohio EUOC customers choosing alternative suppliers receive an additional incentive applied to the shopping credit (generation component) of 45% for residential customers, 30% for commercial customers and 15% for industrial customers. The amount of the incentive is deferred for future recovery from customers. Subject to approval by the PUCO, recovery will be accomplished by extending the respective transition cost recovery period. On October 21, 2003, the Ohio EUOC filed an application with the PUCO to establish generation service rates beginning January 1, 2006, in response to expressed concerns by the PUCO about price and supply uncertainty following the end of the market development period. The filing included two options: o A competitive auction, which would establish a price for generation that customers would be charged during the period covered by the auction, or 40 ~~o A~~Companies' revised Rate Stabilization Plan ~~which would extend~~extends current generation prices through 2008, ensuring adequate generation supply at ~~stable~~stabilized prices, and ~~continuing~~continues the Ohio ~~EUOC's~~Companies' support of energy efficiency and economic development efforts. ~~Under~~Other key components of the ~~first option,~~revised Rate Stabilization Plan include the following:

·	extension of the amortization period for transition costs being recovered through the RTC for OE from 2006 to as late as 2007; for CEI from 2008 to as late as mid-2009 and for TE from mid-2007 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 December 30, 2004, the Ohio ~~EUOC's support~~Companies filed an application with the PUCO seeking tariff adjustments to recover increases of ~~energy-efficiency programs~~approximately $30 million in transmission and ancillary service costs beginning January 1, 2006. The Ohio Companies also filed an application for authority to defer costs associated with MISO Day 1, MISO Day 2, congestion fees, FERC assessment fees, and the potential for continuing the program to give preferred access to nonaffiliated entities to generation capacity if shopping drops below 20%. Under the proposed plan, the Ohio EUOC are requesting: o Extension of the transition cost amortization period for OEATSI rate increase, as applicable, from 2006 to 2007; for CEI from 2008 to mid-2009 and for TE from mid-2007 to mid-2008; o Deferral of interest costs on the accumulated shopping incentives and other cost deferrals as new regulatory assets; and o Ability to initiate a request to increase generation rates under certain limited conditions. On January 7, 2004, the PUCO staff filed testimony on the proposed rate plan generally supporting the Rate Stabilization Plan as opposedOctober 1, 2003 through December 31, 2005.

See Note 13 to the competitive auction proposal. Hearings began on February 11, 2004. On February 23, 2004, after consideration of PUCO Staff comments and testimony as well as those provided by some of the intervening parties, FirstEnergy made certain modifications to the Rate Stabilization Plan. Oral arguments were held before the PUCO on April 21consolidated financial statements for further details and a ~~decision is expected from the PUCO~~complete discussion of regulatory matters in ~~the Spring of 2004.~~ Ohio.

New Jersey Under New Jersey transition legislation, all electric distribution companies were required to file rate cases to determine the level of unbundled rate components to become effective August 1, 2003. JCP&L's two August 2002 rate filings requested increases in base electric rates of approximately $98 million annually and requested the recovery of deferred energy costs that exceeded amounts being recovered under the current MTC and SBC rates; one proposed method of recovery of these costs is the securitization of the deferred balance. This securitization methodology is similar to the Oyster Creek securitization. In

The July 2003 ~~the~~ NJBPU ~~announced its~~decision on JCP&L&L's base electric rate proceeding ~~decision which reduced~~ordered a Phase II proceeding be conducted to review whether JCP~~&L's annual revenues by approximately $62 million effective August 1, 2003.~~&L is in compliance with current service reliability and quality standards. The NJBPU ~~decision~~ also ~~provided for an interim return on equity of 9.5% on JCP&L's rate base for the next six to twelve months. During~~ordered that ~~period,~~any expenditures and projects undertaken by JCP&L ~~will initiate another~~to increase its system's reliability be reviewed as part of the Phase II proceeding, to ~~request recovery of additional costs incurred to enhance system reliability.~~determine their prudence and reasonableness for rate recovery. In that Phase II proceeding, the NJBPU could increase ~~the~~JCP&L’s return on equity to 9.75% or decrease it to 9.25%, depending on its assessment of the reliability of JCP&L's service. Any reduction would be retroactive to August 1, 2003. ~~The revenue decrease in~~On July 16, 2004, JCP&L filed the ~~decision consists of a $223 million decrease in~~Phase II petition and testimony with the electricity delivery charge, a $111 million increase due to the August 1, 2003 expiration of annual customer credits previously mandated by the New Jersey transition legislation, a $49 millionNJBPU, requesting an increase in ~~the MTC tariff component, and a net $1~~base rates of $36 million ~~increase in the SBC charge. The MTC allowed~~ for the recovery of $465 million in deferred energy costs over the next ten years on an interim basis, thus disallowing $153 million of the $618 million provided for in a preliminary settlement agreement between certain parties. As a result, JCP&L recorded charges to net income for the year ended December 31, 2003, aggregating $185 million ($109 million net of tax) consisting of the $153 million deferred energysystem reliability costs and ~~other regulatory assets.~~a 9.75% return on equity. The filing also requests an increase to the MTC deferred balance recovery of approximately $20 million annually. The Ratepayer Advocate filed testimony on November 16, 2004, and JCP&L ~~filed a motion for rehearing~~submitted rebuttal testimony on January 4, 2005. The Ratepayer Advocate surrebuttal testimony was submitted February 8, 2005. Discovery and reconsideration with the NJBPU on August 15, 2003 with respect to the following issues: (1) the disallowance of the $153 million deferred energy costs; (2) the reduced rate of return on equity; and (3) $42.7 million of disallowed costs to achieve merger savings. On October 10, 2003, the NJBPU held the motion in abeyance until the final NJBPU decision and order is issued. This is expected to occur in the second quarter of 2004. On July 5, 2003, JCP&L experienced a series of 34.5 kilo-volt sub-transmission line faults that resulted in outages on the New Jersey shore. The NJBPU instituted an investigation into these outages, and directed that a Special Reliability Master be hired to oversee the investigation. On December 8, 2003, the Special Reliability Master issued his Interim Report recommending that JCP&L implement a series of actions to improve reliability in the area affected by the outages. The NJBPU adopted the findings and recommendations of the Interim Report on December 17, 2003, and ordered JCP&L to implement the recommended actions on a staggered basis, with initial actions to be completed by March 31, 2004. JCP&L expects to spend $12.5 million implementing these actions during 2004. settlement conferences are ongoing.

In ~~late 2003, in~~ accordance with ~~a Settlement Stipulation concerning~~ an ~~August 2002 storm outage, the NJBPU engaged Booth & Associates to conduct an audit of the planning, operations and maintenance practices, policies 41~~ and procedures of JCP&L. The audit was expanded to include the July 2003 outage and was completed in January 2004. JCP&L is awaiting the issuance of the final audit report and is unable to predict the outcome of the audit; no liability has been accrued as of March 31, 2004. On April 28, 2004 ~~the~~ NJBPU ~~directed~~order, JCP&L ~~to file~~filed testimony ~~by the end of May~~on June 7, 2004 ~~either~~ supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey ~~ratepayers, or, alternatively, proposing~~customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L ~~cannot predict~~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 ~~outcome~~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.

See Note 13 to the consolidated financial statements for further details and a complete discussion of ~~this matter. Pennsylvania In June 2001, the PPUC approved the Settlement Stipulation with all of the major parties~~regulatory matters in ~~the combined merger and rate proceedings which approved the FirstEnergy/GPU merger and provided PLR deferred accounting treatment for energy costs, permitting~~ New Jersey.

Pennsylvania

Met-Ed and Penelec to defer, for future recovery, energy costs in excess of amounts reflected in their capped generation rates retroactive to January 1, 2001. This PLR deferral accounting procedure was later reversed in a February 2002 Commonwealth Court of Pennsylvania decision. The court decision affirmed the PPUC decision regarding approval of the merger, remanding the decision to the PPUC only with respect to the issue of merger savings. FirstEnergy established reserves in 2002 for Met-Ed's and Penelec's PLR deferred energy costs which aggregated $287.1 million, reflecting the potential adverse impact of the then pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court decision. FirstEnergy recorded in 2002 an aggregate non-cash charge of $55.8 million ($32.6 million net of tax) to income for the deferred costs incurred subsequent to the merger. The reserve for the remaining $231.3 million of deferred costs increased goodwill by an aggregate net of tax amount of $135.3 million. On April 2, 2003, the PPUC remanded the issue relating to merger savings to the ALJ for hearings, directed Met-Ed and Penelec to file a position paper on the effect of the Commonwealth Court order on the Settlement Stipulation and allowed other parties to file responses to the position paper. Met-Ed and Penelec filed a letter with the ALJ on June 11, 2003, voiding the Stipulation in its entirety and reinstating Met-Ed's and Penelec's restructuring settlement previously approved by the PPUC. On October 2, 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety. The PPUC directed Met-Ed and Penelec to file tariffs within thirty days of the order to reflect the CTC rates and shopping credits that were in effect prior to the June 21, 2001 order to be effective upon one day's notice. In response to that order, Met-Ed and Penelec filed these supplements to their tariffs to become effective October 24, 2003. On October 8, 2003, Met-Ed and Penelec filed a petition for clarification relating to the October 2, 2003 order on two issues: to establish June 30, 2004 as the date to fully refund the NUG trust fund and to clarify that the ordered accounting treatment regarding the CTC rate/shopping credit swap should follow the ratemaking, and that the PPUC's findings would not impair their rights to recover all of their stranded costs. On October 9, 2003, ARIPPA (an intervenor in the proceedings) petitioned the PPUC to direct Met-Ed and Penelec to reinstate accounting for the CTC rate/shopping credit swap retroactive to January 1, 2002. Several other parties also filed petitions. On October 16, 2003, the PPUC issued a reconsideration order granting the date requested by Met-Ed and Penelec for the NUG trust fund refund and, denying Met-Ed's and Penelec's other clarification requests and granting ARIPPA's petition with respect to the retroactive accounting treatment of the changes to the CTC rate/shopping credit swap. On October 22, 2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking that the Court reverse the PPUC's finding that requires Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. On October 27, 2003, one Commonwealth Court judge issued an Order denying Met-Ed's and Penelec's objection without explanation. Due to the vagueness of the Order, Met-Ed and Penelec, on October 31, 2003, filed an Application for Clarification with the judge. Concurrent with this filing, Met-Ed and Penelec, in order to preserve their rights, also filed with the Commonwealth Court both a Petition for Review of the PPUC's October 16 and October 22 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. In addition to these findings, Met-Ed and Penelec, in compliance with the PPUC's Orders, filed revised PPUC quarterly reports for the twelve months ended December 31, 2001 and 2002, and for the first two quarters of 2003, reflecting balances consistent with the PPUC's findings in their Orders. Effective September 1, 2002, Met-Ed and Penelec agreed to purchase a portion of their PLR requirements from FES through a wholesale power ~~sale~~sales agreement. The PLR sale ~~will be~~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 ~~assumed~~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. FES has hedged most of Met-Ed's and Penelec's unfilled PLR on-peak obligation through 2004 and a portion of 2005, the period during which deferred accounting was previously allowed under the PPUC's order. Met-Ed and Penelec are authorized to continue deferring differences between NUG contract costs and current market prices. 42 ~~In late 2003,~~

On January 12, 2005, Met-Ed and Penelec filed, before the PPUC, ~~issued~~ a Tentative Order implementing new reliability benchmarks and standards. In connection therewith, the PPUC commenced a rulemaking procedure to amend the Electric Service Reliability Regulations to implement these new benchmarks, and create additional reporting on reliability. Although neither the Tentative Order nor the Reliability Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on Novemberrequest for deferral of transmission-related costs beginning January 1, 2003. The comment period for both the Tentative Order and the Proposed Rulemaking Order has closed. FirstEnergy is currently awaiting the PPUC to issue a final order in both matters. The order will determine (1) the standards and benchmarks2005, estimated to be ~~utilized,~~approximately $8 million per month.

See Note 13 to the consolidated financial statements for further details and ~~(2) the details required~~a complete discussion of regulatory matters in ~~the quarterly and annual reports.~~ Pennsylvania.

Transmission

On ~~January~~September 16, 2004, the ~~PPUC initiated~~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 decision, CEI may be responsible for a ~~formal investigation~~portion of whether Met-Ed's, Penelec's and Penn's "service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring" in Pennsylvania. Discovery has commencednew energy market charges imposed by MISO when its energy markets begin in the proceeding and Met-Ed's, Penelec's and Penn's testimony is due May 14, 2004. Hearings are scheduled to begin August 3, 2004 in this investigation and the ALJ has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order by year endspring of ~~2004. FirstEnergy is unable to predict the outcome~~2005. CEI filed for rehearing of the ~~investigation or~~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. While the order on rehearing is favorable to CEI, the impact of the ~~PPUC order. Davis-Besse Restoration~~ 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 ~~April 30, 2002,~~November 1, 2004, ATSI requested authority from the ~~NRC initiated a formal inspection process at~~FERC to defer approximately $54 million of vegetation management costs ($14 million deferred as of March 31, 2005) estimated to be incurred from 2004 through 2007. On March 4, 2005, the ~~Davis-Besse nuclear plant. This action was taken in response~~FERC approved ATSI's request to ~~corrosion found by FENOC in the reactor vessel head near the nozzle penetration hole during a refueling outage~~defer those costs. ATSI expects to file an application with FERC in the first quarter of ~~2002. The purpose~~2006 for recovery of the ~~formal inspection process was~~deferred costs.

ATSI and MISO filed with the FERC on December 2, 2004, seeking approval for ATSI to ~~establish criteria~~have transmission rates established based on a FERC-approved cost of service - formula rate included in Attachment O under the MISO tariff. The ATSI Network Service net revenue requirement increased under the formula rate to approximately $159 million. On January 28, 2005, the FERC accepted for ~~NRC oversight~~filing the revised tariff sheets to become effective February 1, 2005, subject to refund, and ordered a public hearing be held to address the reasonableness of the ~~licensee's performance and~~proposal to ~~provide a record of~~eliminate the ~~major regulatory and licensee actions taken, and technical issues resolved. This process led to~~voltage-differentiated rate design for the NRC's March 8, 2004 approval of Davis-Besse's restart. Restart activities included both hardware and management issues. In addition to refurbishment and installation work at the plant, FENOC made significant management and human performance changes with the intent of enhancing the proper safety culture throughout the workforce. The focus of activities in the first quarter of 2004 involved management and human performance issues. As a result, incremental maintenance costs declined in the first quarter of 2004 compared to the same period in 2003 as emphasis shifted to performance issues; however, replacement power costs were higher in the first quarter of 2004. The plant's generating equipment was tested in March in preparation for resumption of operation.ATSI zone. On April 4, ~~2004, Davis-Besse resumed generating electricity at 100% power. Incremental costs associated~~2005, a settlement with all parties to the proceeding was filed with the ~~extended Davis-Besse outage~~FERC that provides for recovery of the ~~first quarter~~full amount of 2004 and 2003 were as follows: Three Months Ended March 31, ------------------- Increase Costs of Davis-Besse Extended Outage 2004 2003 (Decrease) - ----------------------------------------------------------------------------- (In millions) Incremental Expense Replacement power................. $64 $52 $ 12 Maintenance....................... 1 36 (35) - -------------------------------------------------------------------------- Total......................... $65 $88 $(23) ========================================================================== Incremental Net of Tax Expense...... $38 $52 $(14) ========================================================================== the rate increase permitted under the formula.

Environmental Matters ~~Various federal, state and local authorities regulate the~~

The Companies ~~with regard to air and water quality and other~~accrue 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 extentliabilities only when they conclude that it ~~competes with companies~~is probable that ~~are not subject to~~they have an obligation for such ~~regulations~~costs and ~~therefore do not bear~~can reasonably determine the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, FirstEnergy believes it is in material compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effectsamount of such ~~change would be. The EPA has proposed~~costs. Unasserted claims are reflected in the ~~Interstate~~Companies’ determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

National Ambient Air Quality ~~Rule~~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 ~~"cap-and-trade" NOx~~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~~SO₂ emissions in two phases (Phase I in 2009 for NO_x, 2010 for SO₂ and Phase II in ~~2015)~~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~~SO₂ emissions ~~would~~will be reduced by ~~approximately 3.6 million tons in~~45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions ~~ultimately~~ reaching ~~more than 5.5~~73% (from 2003 levels) by 2015, capping SO₂ emissions in affected states to just 2.5 million tons annually. ~~NOx emission~~NO_x emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions ~~would measure about 1.5~~reaching 61% (from 2003 levels) by 2015, achieving a regional NO_x cap of 1.3 million tons ~~in 2010 and 1.8 million tons in 2015.~~annually. The future cost of compliance with these ~~proposed~~ regulations may be substantial and will depend on ~~whether and~~ how they are ultimately implemented by the states in which the Companies operate affected facilities. 43 On

Mercury Emissions

In December ~~15, 2003,~~2000, the EPA ~~proposed two different approaches to reduce~~announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury ~~emissions from coal-fired power plants. The first approach would require plants to install controls known~~ as ~~"maximum achievable control technologies" (MACT) based on~~ the ~~type~~hazardous air pollutant of ~~coal burned. According to~~greatest concern. On March 14, 2005, the EPA ~~if implemented, the MACT proposal would reduce nationwide mercury emissions from coal-fired power plants by 14 tons to approximately 34 tons per year. The second approach proposes~~finalized a cap-and-trade program ~~that would~~to reduce mercury emissions in two ~~distinct phases.~~phases from coal-fired power plants. Initially, mercury emissions ~~would be reduced~~will decline by 2010 as a "co-benefit" from implementation of ~~SO2~~SO₂ and ~~NOx~~NO_x emission caps under the EPA's ~~proposed Interstate Air Quality Rule.~~CAIR program. Phase II of the mercury cap-and-trade program ~~would be implemented in 2018 to~~will cap nationwide mercury emissions from coal-fired power plants at 15 tons per ~~year. The EPA has agreed to choose between these two options and issue a final rule~~year by ~~March 15, 2005.~~2018. The future cost of compliance with these regulations may be substantial.

W. H. Sammis Plant

In 1999 and 2000, the EPA issued ~~Notices of Violation (NOV)~~NOV or a Compliance ~~Order~~Orders to nine utilities covering 44 power plants, including the W. H. Sammis ~~Plant.~~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, which included 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. ~~The ruling concludes~~On March 18, 2005, OE and Penn announced that they had reached a settlement with the ~~liability phase of~~EPA, the ~~case, which deals with applicability of Prevention of Significant Deterioration provisions of~~DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the ~~Clean Air Act. The remedy phase,~~W. H. Sammis Plant New Source Review litigation. This settlement agreement, which is in the form of a Consent Decree subject to a thirty-day public comment period that ended on April 29, 2005 and final approval by the District Court Judge, 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 ~~scheduled~~estimated to be ~~ready~~$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 towards environmentally beneficial projects, which include wind energy purchase power agreements over a 20-year term. OE and Penn also agreed to pay a civil penalty of $8.5 million. Results for ~~trial beginning July 19, 2004, will address civil~~the first quarter of 2005 include the penalties payable by OE and ~~what, if any, actions should be taken to further reduce emissions at~~Penn of $7.8 million and $0.7 million, respectively. OE and Penn also accrued $9.2 million and $0.8 million, respectively, for cash contributions toward environmentally beneficial projects during the plant. In the ruling, the Court indicated that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent effortsfirst quarter of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact on FirstEnergy's financial condition and results of operations. Management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of March 31, 2004. 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 ~~U.S.~~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%~~18 percent through 2012.

The Companies cannot currently estimate the financial impact of climate change policies, although the potential restrictions on ~~CO2~~CO₂ emissions could require significant capital and other expenditures. However, the ~~CO2~~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 ~~includes~~include low or ~~non-CO2~~non-CO₂ emitting gas-fired and nuclear generators. ~~Power Outages In July 1999,~~

FirstEnergy plans to issue a report that will disclose the ~~Mid-Atlantic states experienced a severe heat storm~~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.

Regulation of Hazardous Waste

The Companies have been named as PRPs at waste disposal sites, which ~~resulted in power outages throughout~~may require cleanup under the ~~service territories~~Comprehensive Environmental Response, Compensation, and Liability Act of ~~many electric utilities, including JCP&L's territory. In an investigation into the causes~~1980. Allegations of ~~the outages~~disposal of hazardous substances at historical sites and the ~~reliability of the transmission~~liability involved are often unsubstantiated and ~~distribution systems of~~subject to dispute; however, federal law provides that all ~~four New Jersey electric utilities, the NJBPU concluded~~PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities 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. Since July 1999, this litigation has involved a substantial amount of legal discovery including interrogatories, request for production of documents, preservation and inspection of evidence, and depositions of the named plaintiffs and many JCP&L employees. In addition, thereare considered probable have been ~~many motions filed and argued by~~recognized on the parties involving issues such as the primary jurisdiction and findings of the NJBPU, consumer fraud by JCP&L, strict product liability, class decertification, and the damages claimed by the plaintiffs. In January 2000, the NJ Appellate Division determined that the trial court has proper jurisdiction over this litigation. 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 products 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 have been appealed to the Appellation Division and oral argument is scheduled for May 2004. FirstEnergy is unable to predict the outcome of these matters and no liability has been accruedConsolidated Balance Sheet as of March 31, ~~2004. 44~~ 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 $65 million as of March 31, 2005.

See Note 12(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 FirstEnergy's normal business operations pending against FirstEnergy 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 a widespread power ~~outage. That outage~~outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. ~~On April 5, 2004, the~~The U.S. - ~~-Canada~~Canada Power System Outage Task ~~Force released its~~Force’s final report in April 2004 on ~~this outage. The final report supercedes~~ the ~~interim report that had been issued in November, 2003. In the final report, the Task Force~~outages concluded, among other things, that the problems leading to the ~~outage~~outages began in ~~FirstEnergy's~~FirstEnergy’s Ohio service ~~area. Specifically,~~area.Specifically, the final report concludes, among other things, that the initiation of the August ~~14th~~14, 2003 power ~~outage~~outages resulted from ~~the coincidence on that afternoon of several events, including,~~ 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~~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~~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 ~~14th~~14, 2003 power ~~outage~~outages and that it does not adequately address the underlying causes of the ~~outage.~~outages. FirstEnergy remains convinced that the ~~outage~~outages cannot be explained by events on any one utility's system. The final report ~~contains~~contained 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations ~~relate~~related to broad industry or policy matters while one, ~~relates~~including subparts, related to activities the Task Force ~~recommends~~recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and ~~ECAR.~~other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy ~~has undertaken~~implemented several initiatives, ~~some~~both prior to and ~~some~~ since the August ~~14th~~14, 2003 power ~~outage, to enhance reliability~~outages, which ~~are~~were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and ~~believes it will complete those relating to summer 2004 by June 30 (see Regulatory Matters above).~~collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these initiatives already were in process, ~~and budgeted in 2004,~~ FirstEnergy does not believe that any incremental expenses associated with additional initiatives ~~undertaken during~~completed in 2004 ~~will have~~had a material effect on its continuing operations or financial results. FirstEnergy notes, however, that the 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. ~~Davis-Besse~~ FirstEnergy has not accrued a liability as of March 31, 2005 for any expenditures in excess of those actually incurred through that date.

On April 21, 2005, the NRC ~~on March 29, 2004 by~~issued a ~~group objecting~~NOV and proposed a $5.45 million civil penalty related to the ~~NRC's restart order~~degradation of the Davis-Besse ~~Nuclear Power Station. The Petition seeks, among other things, suspension~~reactor vessel head described above. Under the NRC’s letter, FENOC has ninety days to respond to this NOV. FirstEnergy has accrued the remaining liability for the proposed fine of $3.45 million during the ~~Davis-Besse operating license.~~first quarter of 2005.

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 past two years. FENOC operates the Perry Nuclear Power Plant, which is owned and/or leased by OE, CEI, TE and ~~proceedings related~~Penn.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. 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 ~~normal business operations are pending against~~or its subsidiaries' financial condition.

On October 20, 2004, FirstEnergy ~~and its subsidiaries. The most significant not otherwise discussed above are described below. Legal proceedings have been filed against FirstEnergy~~was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in ~~connection with, among other things,~~September 2003 relating to the restatements in August 2003 ~~by FirstEnergy and its Ohio utility subsidiaries~~ of previously reported results ~~the August 14th power outage described above,~~by FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, athave become the ~~Davis-Besse Nuclear Power Station. Depending upon the particular proceeding, the~~subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised ~~include alleged violations~~during the SEC's examination of ~~federal securities laws, breaches of fiduciary duties~~FirstEnergy and the Companies under ~~state law by~~the PUHCA. Concurrent with this notification, FirstEnergy ~~directors~~received a subpoena asking for background documents and ~~officers,~~documents related to the restatements and ~~damages as~~Davis-Besse issues. On December 30, 2004, FirstEnergy received a ~~result of one or more of~~second subpoena asking for documents relating to issues raised during the noted events. The securities cases have been consolidated into one action pending in federal court in Akron. The derivative actions filed in federal court likewise have been consolidated as a separate matter, also in federal court in Akron. There also are pending derivative actions in state court. FirstEnergy's Ohio utility subsidiaries were also named as respondents in two regulatory proceedings initiated atSEC's PUHCA examination. FirstEnergy has cooperated fully with the ~~PUCO in response~~informal inquiry and will continue to ~~complaints alleging failure to provide reasonable and adequate service stemming primarily from~~do so with the August 14th power outage. 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 instituted against them. In particular, if FirstEnergyformal investigation.

If it were ultimately determined tothat FirstEnergy or its subsidiaries have legal liability ~~in connection with these proceedings,~~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. ~~Three substantially similar actions were filed in various Ohio state courts by plaintiffs seeking~~

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

FIN 47,“Accounting for Conditional Asset Retirement Obligations - an interpretation of ~~judgment, estimates and assumptions that affect financial results. All of FirstEnergy's assets are subject~~FASB Statement No. 143”

On March 30, 2005, the FASB issued this interpretation to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. FirstEnergy's more significant accounting policies are described below. Regulatory Accounting FirstEnergy's regulated services segment is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine FirstEnergy is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in each state in which FirstEnergy operates, a significant amount of regulatory assets have been recorded - $6.7 billion as of March 31, 2004. FirstEnergy regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall withinclarify the scope and timing of ~~SFAS 133, as amended, must be recorded at their~~liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair ~~value. Active market prices are not always available to determine~~value of an asset retirement obligation that is conditional on a future event, if the fair value of the ~~later years of a contract, requiring that various assumptions and estimates~~liability can be ~~used in their valuation. FirstEnergy continually monitors its derivative contracts~~reasonably estimated. In instances where there is insufficient information to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, FirstEnergy enters into a significant number of commodity contracts, as well as interest rate swaps, which increaseestimate the ~~impact of derivative accounting judgments. Revenue Recognition FirstEnergy follows~~liability, the ~~accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered~~obligation is to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class and electricity provided from alternative suppliers. Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87 and SFAS 106, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. 46 In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to recent declines in corporate bond yields and interest rates in general, FirstEnergy reduced the assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first quarter of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Ohio Transition Cost Amortization In connection with FirstEnergy's transition plan, the PUCO determined allowable transition costs based on amounts recorded on the regulatory books of the Ohio electric utilities. These costs exceeded those deferred or capitalized on FirstEnergy's balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). FirstEnergy uses an effective interest method for amortizing its transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the transition plan for each respective company. In computing the transition cost amortization, FirstEnergy includes only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received. Long-Lived Assets In accordance with SFAS 144, FirstEnergy periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the ~~financial statements.~~first period in which sufficient information becomes available to estimate its fair value. If impairment has occurred, FirstEnergy recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). The calculation of future cash flows is based on assumptions, estimates and judgement about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. Nuclear Decommissioning In accordance with SFAS 143, FirstEnergy recognizes an ARO for the future decommissioning of its nuclear power plants. The ARO liability represents an estimate of the fair value ~~of FirstEnergy's current obligation related to nuclear decommissioning~~cannot be reasonably estimated, that fact and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FirstEnergy used an expected cash flow approach (as discussed in FASB Concepts Statement No. 7, "Using Cash Flow Information and Present Value in Accounting Measurements") to measure the fair value of the nuclear decommissioning ARO.reasons why must be disclosed. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants' current license and settlement based on an extended license term. Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, FirstEnergy evaluates goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If an impairment is indicated FirstEnergy recognizes a loss - calculated as the difference between the implied fair value of a reporting 47 unit's goodwill and the carrying value of the goodwill. FirstEnergy's annual review was completed in the third quarter of 2003. As a result of that review, a non-cash goodwill impairment charge of $122 million was recognized in the third quarter of 2003, reducing the carrying value of FSG. The forecasts used in FirstEnergy's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on FirstEnergy's future evaluations of goodwill. As of March 31, 2004, FirstEnergy had $6.1 billion of goodwill that primarily relates to its regulated services segment. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS EITF Issue No. 03-6, "Participating Securities and the Two-Class Method Under Financial Accounting Standards Board Statement No. 128, Earnings per Share" On March 31, 2004, the FASB ratified the consensus reached by the EITF on Issue 03-6. The issue addresses a number of questions regarding the computation of earnings per share by companies that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of a company when, and if, it declares dividends on its common stock. The issue also provides further guidance in applying the two-class method of computing earnings per share once it is determined that a security is participating, including how to allocate undistributed earnings to such a security. EITF 03-06interpretation is effective ~~for~~no later than the end of fiscal ~~periods beginning~~years ending after ~~March 31, 2004.~~December 15, 2005. FirstEnergy is currently evaluating the effect of adopting EITF 03-6. FSP 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" Issued January 12, 2004, FSP 106-1 permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Medicare Act. FirstEnergy elected to defer the effects of the Medicare Act due to the lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 as a result of a February 2, 2004 plan amendment that required remeasurement of the plan's obligations. See Note 2 for a discussion of the effect of the federal subsidy and plan amendmentthis standard will have on the ~~consolidated~~ financial statements. ~~FIN 46~~

SFAS 123 (revised ~~December 2003)~~2004), ~~"Consolidation of Variable Interest Entities"~~ “Share-Based Payment”

In December ~~2003,~~2004, the FASB issued ~~a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", referred~~this revision to ~~as FIN 46R,~~SFAS 123, which requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, FirstEnergy adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. Adoption of FIN 46R did not have a material impact on FirstEnergy's financial statements for the quarter ended March 31, 2004. For the quarter ended March 31, 2004, FirstEnergy evaluated, among other entities, its power purchase agreements and determined that it is possible that nine NUG entities might be considered variable interest entities. FirstEnergy has requested but not received the information necessary to determine whether these entities are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. In most cases, the requested information was deemed to be competitive and proprietary data. 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 increasesexpensing stock options in the ~~variable pricing component under~~financial statements. Important to applying the ~~contract terms~~new standard is understanding how to (1) measure the fair value of stock-based compensation awards and ~~cannot~~(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 ~~determined~~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. 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 ~~requested data. Purchased power costs from these entities during the first quarters of 2004~~Black-Scholes option-pricing model to value options and 2003 were $51 million (JCP&L - $28 million, Met-Ed - $16 million and Penelec - $7 million) and $56 million (JCP&L - $34 million, Met-Ed - $15 million and Penelec - $7 million), respectively. FirstEnergy is required towill continue to ~~make exhaustive efforts to obtain the necessary information in future periods and is unable to determine the possible impact~~do so upon adoption of ~~consolidating any such entity without this information.~~SFAS 123(R).

EITF Issue No. ~~03-11, "Reporting Realized Gains~~03-1, "The Meaning of Other-Than-Temporary Impairment and ~~Losses on Derivative Instruments That Are Subject~~its Application to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not "Held for Trading Purposes" as Defined in EITF Issue 02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." Certain Investments"

In ~~July 2003,~~March 2004, the EITF reached a consensus that determining whether realized gains and losses on physically settled derivative contracts not "held for trading purposes" should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the ~~relevant facts~~application guidance for Issue 03-1. EITF 03-1 provides a model for determining when investments in certain debt and ~~circumstances.~~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 ~~consideration~~recognition and measurement provisions of EITF 03-1, which were to be effective for periods beginning after June 15, 2004, were delayed by the ~~facts and circumstances, including economic substance, should be made~~issuance of FSP EITF 03-1-1 in September 2004. During the ~~context~~period of ~~the various activities~~delay, FirstEnergy will continue to evaluate its investments as required by existing authoritative guidance.

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

		Three Months Ended
		March 31,

		2005			2004

STATEMENTS OF INCOME		*(In thousands)*

OPERATING REVENUES		$	726,358		$	743,295
	��
OPERATING EXPENSES AND TAXES:
Fuel			11,916			15,070
Purchased power			246,590			249,881
Nuclear operating costs			95,653			79,641
Other operating costs			83,179			85,360
Provision for depreciation			26,052			29,929
Amortization of regulatory assets			111,771			113,695
Deferral of new regulatory assets			(24,795	)		(18,895	)
General taxes			48,078			48,566
Income taxes			54,972			61,574
Total operating expenses and taxes			653,416			664,821

OPERATING INCOME			72,942			78,474

OTHER INCOME (net of income taxes)			423			16,357

NET INTEREST CHARGES:
Interest on long-term debt			15,609			16,589
Allowance for borrowed funds used during construction and capitalized interest			(2,235	)		(1,381	)
Other interest expense			2,594			2,890
Subsidiary's preferred stock dividend requirements			640			640
Net interest charges			16,608			18,738

NET INCOME			56,757			76,093

PREFERRED STOCK DIVIDEND REQUIREMENTS			659			561

EARNINGS ON COMMON STOCK		$	56,098		$	75,532

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME		$	56,757		$	76,093

OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gain (loss) on available for sale securities			(2,717	)		5,167
Income tax related to other comprehensive income			1,124			(2,131	)
Other comprehensive income (loss), net of tax			(1,593	)		3,036

TOTAL COMPREHENSIVE INCOME		$	55,164		$	79,129


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

OHIO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2005			2004
	*(In thousands)*
ASSETS
UTILITY PLANT:
In service	$	5,470,159		$	5,440,374
Less - Accumulated provision for depreciation		2,747,377			2,716,851
		2,722,782			2,723,523
Construction work in progress-
Electric plant		233,967			203,167
Nuclear fuel		39,468			21,694
		273,435			224,861
		2,996,217			2,948,384
OTHER PROPERTY AND INVESTMENTS:
Investment in lease obligation bonds		354,457			354,707
Nuclear plant decommissioning trusts		445,704			436,134
Long-term notes receivable from associated companies		208,364			208,170
Other		42,720			48,579
		1,051,245			1,047,590
CURRENT ASSETS:
Cash and cash equivalents		1,204			1,230
Receivables-
Customers (less accumulated provisions of $6,179,000 and $6,302,000, respectively,
for uncollectible accounts)		267,911			274,304
Associated companies		163,201			245,148
Other (less accumulated provisions of $82,000 and $64,000, respectively,
for uncollectible accounts)		20,602			18,385
Notes receivable from associated companies		692,715			538,871
Materials and supplies, at average cost		105,906			90,072
Prepayments and other		25,981			13,104
		1,277,520			1,181,114
DEFERRED CHARGES:
Regulatory assets		1,022,241			1,115,627
Property taxes		61,419			61,419
Unamortized sale and leaseback costs		58,896			60,242
Other		71,327			68,275
		1,213,883			1,305,563
	$	6,538,865		$	6,482,651
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 175,000,000 shares - 100 shares outstanding	$	2,098,729		$	2,098,729
Accumulated other comprehensive loss		(48,711	)		(47,118	)
Retained earnings		451,296			442,198
Total common stockholder's equity		2,501,314			2,493,809
Preferred stock		60,965			60,965
Preferred stock of consolidated subsidiary		39,105			39,105
Long-term debt and other long-term obligations		1,098,801			1,114,914
		3,700,185			3,708,793
CURRENT LIABILITIES:
Currently payable long-term debt		397,256			398,263
Short-term borrowings-
Associated companies		75,969			11,852
Other		134,072			167,007
Accounts payable-
Associated companies		151,151			187,921
Other		7,498			10,582
Accrued taxes		197,848			153,400
Other		126,265			74,663
		1,090,059			1,003,688
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		726,080			766,276
Accumulated deferred investment tax credits		59,135			62,471
Asset retirement obligation		344,715			339,134
Retirement benefits		309,915			307,880
Other		308,776			294,409
		1,748,621			1,770,170
COMMITMENTS AND CONTINGENCIES (Note 12)
	$	6,538,865		$	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
	March 31,

	2005			2004

	*(In thousands)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	56,757		$	76,093
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		26,052			29,929
Amortization of regulatory assets		111,771			113,695
Deferral of new regulatory assets		(24,795	)		(18,895	)
Nuclear fuel and lease amortization		9,170			11,261
Amortization of lease costs		33,030			33,030
Deferred income taxes and investment tax credits, net		(24,627	)		(30,045	)
Accrued retirement benefit obligations		2,034			11,123
Accrued compensation, net		(4,007	)		4,522
Decrease (Increase) in operating assets:
Receivables		86,123			(51,935	)
Materials and supplies		(15,834	)		(2,762	)
Prepayments and other current assets		(12,877	)		(11,829	)
Increase (Decrease) in operating liabilities:
Accounts payable		(39,854	)		240,979
Accrued taxes		44,448			(311,577	)
Accrued interest		6,993			5,443
Other		11,714			5,991
Net cash provided from operating activities		266,098			105,023

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		--			30,000
Short-term borrowings, net		31,182			16,341
Redemptions and Repayments-
Long-term debt		(15,787	)		(97,001	)
Dividend Payments-
Common stock		(47,000	)		(54,000	)
Preferred stock		(659	)		(561	)
Net cash used for financing activities		(32,264	)		(105,221	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(79,783	)		(37,661	)
Contributions to nuclear decommissioning trusts		(7,885	)		(7,885	)
Loan repayments from (loans to) associated companies, net		(154,038	)		48,912
Other		7,846			(3,728	)
Net cash used for investing activities		(233,860	)		(362	)

Net decrease in cash and cash equivalents		(26	)		(560	)
Cash and cash equivalents at beginning of period		1,230			1,883
Cash and cash equivalents at end of period	$	1,204		$	1,323


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

Report of the entity rather than based solely on the terms of the individual contracts. The adoption of this consensus effective January 1, 2004, did not have a material impact on the Companies' financial statements. 48 ~~OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited)~~
Three Months Ended March 31, ------------------------- 2004 2003 -------- -------- (In thousands) OPERATING REVENUES.............................................................. $743,295 $742,743 -------- -------- OPERATING EXPENSES AND TAXES: Fuel......................................................................... 15,070 12,850 Purchased power.............................................................. 249,881 243,828 Nuclear operating costs...................................................... 79,641 125,368 Other operating costs........................................................ 81,474 90,273 -------- -------- Total operation and maintenance expenses................................... 426,066 472,319 Provision for depreciation and amortization.................................. 124,729 108,385 General taxes................................................................ 48,566 48,256 Income taxes................................................................. 61,574 43,701 -------- -------- Total operating expenses and taxes......................................... 660,935 672,661 -------- -------- OPERATING INCOME................................................................ 82,360 70,082 OTHER INCOME.................................................................... 12,471 13,501 -------- -------- INCOME BEFORE NET INTEREST CHARGES.............................................. 94,831 83,583 -------- -------- NET INTEREST CHARGES: Interest on long-term debt................................................... 16,589 24,488 Allowance for borrowed funds used during construction and capitalized interest (1,381) (1,380) Other interest expense....................................................... 2,890 2,478 Subsidiaries' preferred stock dividend requirements.......................... 640 912 -------- -------- Net interest charges....................................................... 18,738 26,498 -------- -------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................ 76,093 57,085 Cumulative effect of accounting change (net of income taxes of $22,389,000) (Note 2) -- 31,720 ------- -------- NET INCOME...................................................................... 76,093 88,805 PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 561 659 -------- -------- EARNINGS ON COMMON STOCK........................................................ $ 75,532 $ 88,146 ======== ======== ~~The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these statements.~~ 49
~~OHIO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)~~
March 31, December 31, 2004 2003 ---------- ----------- (In thousands) ASSETS UTILITY PLANT: In service...................................................................... $5,304,122 $5,269,042 Less-Accumulated provision for depreciation..................................... 2,611,122 2,578,899 ---------- ---------- 2,693,000 2,690,143 ---------- ---------- Construction work in progress- Electric plant................................................................ 143,478 145,380 Nuclear Fuel.................................................................. 554 554 ---------- ---------- 144,032 145,934 ---------- ---------- 2,837,032 2,836,077 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Investment in lease obligation bonds............................................ 383,088 383,510 Letter of credit collateralization.............................................. -- 277,763 Nuclear plant decommissioning trusts............................................ 394,705 376,367 Long-term notes receivable from associated companies ........................... 209,271 508,594 Other........................................................................... 56,131 59,102 ---------- ---------- 1,043,195 1,605,336 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents....................................................... 1,323 1,883 Receivables- Customers (less accumulated provisions of $8,714,000 and $8,747,000, respectively, for uncollectible accounts)................................... 267,315 280,538 Associated companies.......................................................... 500,570 436,991 Other (less accumulated provisions of $1,724,000 and $2,282,000 for uncollectible accounts)................................................. 29,887 28,308 Letter of credit collateralization.............................................. 277,763 -- Notes receivable from associated companies...................................... 616,912 366,501 Materials and supplies, at average cost......................................... 82,575 79,813 Prepayments and other........................................................... 26,219 14,390 ---------- ---------- 1,802,564 1,208,424 ---------- ---------- DEFERRED CHARGES: Regulatory assets............................................................... 1,363,242 1,477,969 Property taxes.................................................................. 59,279 59,279 Unamortized sale and leaseback costs............................................ 64,284 65,631 Other........................................................................... 64,353 64,214 ---------- ---------- 1,551,158 1,667,093 ---------- ---------- $7,233,949 $7,316,930 ========== ========== CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common stockholder's equity- Common stock, without par value, authorized 175,000,000 shares - 100 shares outstanding............................................. $2,098,729 $2,098,729 Accumulated other comprehensive loss.......................................... (35,657) (38,693) Retained earnings............................................................. 544,466 522,934 ---------- ---------- Total common stockholder's equity........................................... 2,607,538 2,582,970 Preferred stock not subject to mandatory redemption............................. 60,965 60,965 Preferred stock of consolidated subsidiary not subject to mandatory redemption.. 39,105 39,105 Long-term debt and other long-term obligations.................................. 1,160,452 1,179,789 ---------- ---------- 3,868,060 3,862,829 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock............................ 428,438 466,589 Short-term borrowings- Associated companies.......................................................... 67,849 11,334 Other......................................................................... 131,367 171,540 Accounts payable- Associated companies.......................................................... 512,386 271,262 Other......................................................................... 7,834 7,979 Accrued taxes................................................................... 248,768 560,345 Accrued interest................................................................ 24,157 18,714 Other........................................................................... 99,116 58,680 ---------- ---------- 1,519,915 1,566,443 ---------- ---------- NONCURRENT LIABILITIES: Accumulated deferred income taxes............................................... 824,832 867,691 Accumulated deferred investment tax credits..................................... 72,664 75,820 Asset retirement obligation..................................................... 322,929 317,702 Retirement benefits............................................................. 342,952 331,829 Other........................................................................... 282,597 294,616 ---------- ---------- 1,845,974 1,887,658 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................. ---------- ---------- $7,233,949 $7,316,930 ========== ========== ~~The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these balance sheets.~~ 50
~~OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)~~
Three Months Ended March 31, ---------------------------- 2004 2003 --------- --------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income...................................................................... $ 76,093 $ 88,805 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization................................ 124,729 108,385 Nuclear fuel and lease amortization........................................ 11,261 7,106 Deferred income taxes, net................................................. (26,387) 7,683 Investment tax credits, net................................................ (3,658) (3,704) Cumulative effect of accounting change (Note 2)............................ -- (54,109) Receivables................................................................ (51,935) (29,909) Materials and supplies..................................................... (2,762) (1,298) Accounts payable........................................................... 240,979 14,470 Accrued taxes.............................................................. (311,577) 6,051 Accrued interest........................................................... 5,443 2,437 Deferred lease costs....................................................... 33,030 31,683 Prepayments and other current assets ...................................... (11,829) (14,893) Accrued retirement benefit obligations..................................... 11,123 2,679 Accrued compensation, net.................................................. 4,404 (5,802) Other...................................................................... 16,562 (6,067) --------- --------- Net cash provided from operating activities.............................. 115,476 153,517 --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt............................................................. 30,000 -- Short-term borrowings, net................................................. 16,341 -- Redemptions and Repayments- Long-term debt............................................................. (97,001) (19,493) Short-term borrowings, net................................................. -- (232,278) Dividend Payments- Common stock............................................................... (54,000) (13,000) Preferred stock............................................................ (561) (659) --------- --------- Net cash used for financing activities................................... (105,221) (265,430) --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................... (37,661) (68,367) Contributions to nuclear decommissioning trusts.............................. (7,885) (7,885) Nuclear decommissioning trust investments.................................... (10,453) 4,777 Associated company loan activities, net...................................... 48,912 173,250 Other........................................................................ (3,728) 3,946 --------- --------- Net cash provided from (used for) investing activities................... (10,815) 105,721 --------- --------- Net decrease in cash and cash equivalents....................................... (560) (6,192) Cash and cash equivalents at beginning of period................................ 1,883 20,512 --------- --------- Cash and cash equivalents at end of period...................................... $ 1,323 $ 14,320 ========= ========= ~~The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these statements.~~ 51
~~REPORT OF INDEPENDENT ACCOUNTANTS~~ 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 March 31, ~~2004,~~2005, and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, ~~2004~~2005 and ~~2003.~~2004. These interim financial statements are the responsibility of the ~~Company's~~Company’s management.

We previously audited, in accordance with ~~auditing~~the standards ~~generally accepted in~~of the ~~United States of America,~~Public Company Accounting Oversight Board (United States), the consolidated balance sheet ~~and the consolidated statement of capitalization~~ as of December 31, ~~2003,~~2004, and the related consolidated statements of income, capitalization, common ~~stockholder's~~stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, ~~(not presented herein),~~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~~Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note ~~1(F)~~2(G) to those consolidated financial statements and the ~~Company's~~Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 67 to those consolidated financial statements) dated ~~February 25, 2004,~~March 7, 2005, we expressed an unqualified ~~opinion on those~~opinions thereon. The consolidated financial ~~statements.~~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 ~~condensed~~ consolidated balance sheet information as of December 31, ~~2003,~~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

May ~~7, 2004 52~~ 3, 2005

OHIO EDISON COMPANY ~~MANAGEMENT'S~~

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 ~~and Penn (OE Companies)~~Companies also provide generation services to those customers electing to retain ~~them~~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~~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 first quarter of ~~2004~~2005 decreased to ~~$76~~$56 million from ~~$88~~$76 million in the first quarter of ~~2003. Earnings on common stock~~2004. The earnings decrease in ~~the first quarter of 2003 included an after-tax credit of $32 million~~2005 primarily resulted from the cumulative effect of an accounting change due to the adoption of SFAS 143. Income before the cumulative effect was $76 million in the first three months of 2004, compared to $57 million for the same period of 2003. Improved results in the first quarter of 2004 reflect lowerreduced operating ~~expenses - primarily~~revenues and other income and increased nuclear operating costs, which were partially offset by decreased depreciation, changes in amortization and ~~reduced financing costs compared with the first quarter~~deferrals of ~~2003. Partially offsetting these improvements were higher nuclear~~regulatory assets, lower fuel and purchased power costs, and ~~increased amortization of regulatory assets.~~ reduced financing costs.

Operating revenues ~~increased~~decreased by ~~$0.6~~$17 million or ~~0.1%~~2.3% in the first quarter of ~~2004~~2005 compared with the same period in ~~2003. The higher~~2004. Lower revenues primarily resulted from ~~additional~~a $24 million wholesale sales decrease partially offset by increases in retail generation and distribution revenues of $6 million and $2 million, respectively.

Lower wholesale revenues reflected decreased sales to FES ~~which~~of $28 million (20.3% KWH decrease) due to reduced nuclear generation available for sale. The decreased FES sales were ~~substantially~~partially offset by ~~lower~~increased sales of $4 million to non-affiliated customers (primarily MSG sales). Under its Ohio transition plan, OE is required to provide the attractively-priced MSG to non-affiliated alternative suppliers (see Outlook - Regulatory Matters).

Increased retail generation ~~retail~~revenues resulted from increased sales to ~~residential~~industrial and commercial customers of $5 million and ~~reduced revenue from distribution throughput. Total retail electric revenues decreased by $7~~$3 million, in the first quarter of 2004 compared to the first quarter of 2003 reflecting reduced consumption due principally to milder weather and a continued sluggish economy in our service area ($13 million)respectively, partially offset by a $2 million residential sales decrease. The increase in industrial and commercial revenues reflected the effect of higher generation KWH sales (industrial - 4.1% and commercial - 3.9%) and higher composite ~~prices from a change in~~unit prices. The industrial KWH growth was moderated by increased customer ~~sales by class ($6 million). Kilowatt-hour sales~~shopping. Generation services provided to ~~retail~~industrial customers declined by 3.3% in the first quarter of 2004 compared to the same quarter of 2003, which reduced generation sales revenue by $2 million. The decline reflected the increase of 2.3 percentage points in electric generation services provided by alternative suppliers as a percent of total industrial sales delivered in ~~OE's franchise~~OE’s service area in 2004 from the first quarter of 2003. In addition, distribution deliveries decreased by 1.6% in the first quarter of 2004 compared with the first quarter of 2003, with declines in all customer sectors (residential, commercial and industrial). Sales revenues from wholesale customers increased by ~~$10~~2.1 percentage points, which partially offset the effect of a 7.2% increase in industrial sector deliveries. Reduced residential revenues were principally due to a 2.8% KWH sales decrease reflecting increased residential customer shopping (1.7 percentage point increase). Commercial customer shopping remained relatively unchanged.

Revenues from distribution throughput increased $2 million in the first quarter of 2005 compared with the same period in 2004. Distribution deliveries to commercial and industrial customers increased by $2 million and $1 million, respectively, in 2005 compared to 2004, reflecting increased KWH deliveries partially offset by lower composite unit prices. The increased sales to the commercial and industrial sectors resulted, in part, from an improving economy in OE's service area. Distribution deliveries to residential customers decreased slightly.

Under the Ohio transition plan, OE provides incentives to customers to encourage switching to alternative energy providers. OE’s revenues were reduced by $2 million from additional credits in the first quarter of 2005 compared to the same period ~~of 2003, due to a 23% increase~~ in ~~nuclear generation available~~2004. These revenue reductions are deferred for ~~sale to FES partially offset by lower composite prices. The increased generation was due to the absence in 2004 of the Beaver Valley Unit 1 refueling outage in 2003.~~ future recovery 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 first quarter of ~~2004~~2005 from the same quarter of ~~2003~~2004 are summarized in the following table: Changes in Kilowatt-Hour Sale --------------------------------------------------- Increase (Decrease) Electric Generation: Retail.................................. (3.3)% Wholesale............................... 9.1% --------------------------------------------------- Total Electric Generation Sales........... 2.2% =================================================== Distribution Deliveries: Residential............................. (2.1)% Commercial.............................. (0.6)% Industrial.............................. (1.8)% ---------------------------------------------------- Total Distribution Deliveries............. (1.6)% ==================================================== 53

Changes in KWH Sales
Increase (Decrease)

Electric Generation:
Retail	1.3	%
Wholesale	(17.4	)%
Total Electric Generation Sales	(7.6	)%
Distribution Deliveries:
Residential	(0.7	)%
Commercial	3.6	%
Industrial	7.2	%
Total Distribution Deliveries	3.1	%

Operating Expenses and Taxes

Total operating expenses and taxes decreased by ~~$12~~$11 million in the first quarter of ~~2004~~2005 from the first quarter of ~~2003.~~2004. The following table presents changes from the prior year by expense category. Operating Expenses and Taxes - Changes ----------------------------------------------------------------- Increase (Decrease) (In millions) Fuel............................................. $ 2 Purchased power ................................. 6 Nuclear operating costs.......................... (45) Other operating costs............................ (9) ------------------------------------------------------------- Total operation and maintenance expenses....... (46) Provision for depreciation and amortization...... 16 General taxes.................................... -- Income taxes..................................... 18 ------------------------------------------------------------ Total operating expenses and taxes............. $(12) ============================================================= Higher

Operating Expenses and Taxes - Changes
Increase (Decrease)	*(In millions)*

Fuel costs	$	(3	)
Purchased power costs		(3	)
Nuclear operating costs		16
Other operating costs		(2	)
Provision for depreciation		(4	)
Amortization of regulatory assets		(2	)
Deferral of new regulatory assets		(6	)
General taxes		--
Income taxes		(7	)
Net decrease in operating expenses and taxes	$	(11	)

Lower fuel costs in the first quarter of ~~2004,~~2005, compared with the same quarter of ~~2003,~~2004, resulted from ~~increased~~decreased nuclear generation - ~~23%~~down 20.3%. ~~Purchased~~Decreased purchased power costs ~~increased by $6 million reflecting higher unit costs which were~~reflected lower KWH purchased partially offset by ~~lower kilowatt-hour purchases~~higher unit costs. Higher nuclear operating costs were primarily due to the ~~decreased requirements for retail generation sales. Lower~~Perry nuclear ~~operating costs occurred in large part due to the absence of the Beaver Valley Unit 1 (100% ownership)~~plant scheduled refueling outage ~~that occurred~~(including an unplanned extension) in the first quarter of ~~2003.~~2005 and the absence of nuclear refueling outages in the same period last year. The decrease in other operating costs ~~reflects in part~~was primarily due to reduced labor costs and lower employee benefit ~~costs. Charges~~expenses.

The decrease in depreciation in the first quarter of 2005 compared with the same quarter of 2004 was attributable to revised estimated service life assumptions for ~~depreciation~~fossil generating plants. Lower amortization of regulatory assets was due to decreased amortization of Ohio transition regulatory assets, effective April 1, 2004. The higher deferrals of new regulatory assets primarily resulted from higher shopping incentive deferrals ($2 million) and ~~amortization increased by~~deferred interest on shopping incentives ($3 million).

Other Income

Other income decreased $16 million in the first quarter of 2005 compared with the same quarter of 2004, ~~compared~~primarily due to the ~~first quarter~~accruals of ~~2003 primarily from two factors~~an $8.5 million civil penalty payable to the Department of Justice and $10 million for environmental projects in connection with the Sammis Plant settlement (see Outlook - increased amortization of the Ohio transition regulatory assets ($14 million) and lower shopping incentive deferrals ($1 million), partially offset by increased regulatory asset deferrals of $2 million. Environmental Matters).

Net Interest Charges

Net interest charges continued to trend lower, decreasing by $8$2 million in the first quarter of ~~2004 from~~2005 compared with the same ~~period last year,~~quarter of 2004, reflecting redemptions ~~and refinancings since the first quarter~~ of ~~2003. OE Companies' net~~$15 million of outstanding debt ~~redemptions totaled $55 million~~ during the first quarter of 2004 and are expected to result in annualized savings of $4 million (excluding change in revolver facilities). Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, OE recorded an after-tax credit to net income of $32 million. The cumulative adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $54 million increase to income, or $32 million net of income taxes. 2005.

Capital Resources and Liquidity ~~- ------------------------------- OE's~~

OE’s cash requirements in ~~2004~~2005 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing ~~its~~OE’s net debt and preferred stock outstanding. Available borrowing capacity under ~~short-term~~ credit facilities will be used to manage working capital requirements. ~~Over the next three years, OE expects to meet its contractual obligations with cash from operations.~~ Thereafter, OE expects to use a combination of cash from operations and funds from the capital markets.

Changes in Cash Position ~~As of March 31, 2004, OE had $1 million of~~

OE's cash and cash equivalents ~~compared with $2~~were approximately $1 million as of March 31, 2005 and December 31, ~~2003. The major sources for changes in these balances are summarized below.~~ 2004.

Cash Flows From Operating Activities

Cash provided byfrom operating activities during the first quarter of 2005 and 2004 ~~compared with the corresponding~~ period ~~in 2003~~ were as follows: 54 Operating Cash Flows 2004 2003 ------------------------------------------------------------- (In millions)

Operating Cash Flows	2005		2004
	*(In millions)*
Cash earnings (1)	$	185	$	231
Working capital and other		81		(126	)
Total Cash Flows from Operating Actitivities	$	266	$	105

⁽¹⁾Cash earnings ~~(1).................... $230 $183 Working capital~~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. FirstEnergy believes that cash earnings is a useful financial measure because it provides investors and other............ (115) (29) ------------------------------------------------------------- Total................................ $115 $154 ============================================================= (1) Includesmanagement with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net ~~income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges.~~ income.

Reconciliation of Cash Earnings	2005			2004
	*(In millions)*

Net Income (GAAP)	$	57		$	76
Non-Cash Charges (Credits):
Provision for depreciation		26			30
Amortization of regulatory assets		112			114
Nuclear fuel and capital lease amortization		9			11
Deferral of new regulatory assets		(25	)		(19	)
Deferred income taxes and investment tax credits, net		(25	)		(30	)
Other non-cash charges		31			49
Cash earnings (Non-GAAP)	$	185		$	231

Net cash from operating activities ~~decreased $39~~increased $161 million in the first quarter of 2005, compared with the first quarter of 2004, due to ~~an $86~~a $207 million increase from changes in ~~funds used for~~ working capital ~~-- that decrease was~~partially offset ~~in part~~ by a ~~$47~~$46 million decrease in cash earnings as described above and under "Results from Operations". The increase in ~~cash earnings. The decrease from~~ working capital ~~and other changes~~ primarily reflects ~~the change~~changes in ~~cash requirements for~~receivables from associated companies of $146 million and accounts payable to associated companies of ~~$227~~$278 million, partially offset by changes in accrued taxes of $356 million. The changes for accounts payable and accrued taxes ~~of $318 million for the first quarter of 2004 as compared to 2003. Both variances~~primarily reflect ~~offsetting changes of~~a $249 million ~~for the~~ reallocation of tax liabilities between associated companies ~~related to~~under the tax sharing ~~agreement.~~ agreement in 2004.

Cash Flows From Financing Activities ~~In the first quarter of 2004, net~~

Net cash used for financing activities decreased to ~~$105 million from $265~~$32 million in the ~~same period last year.~~first quarter of 2005 from $105 million in the first quarter of 2004. The decrease ~~resulted from increased short-term borrowings partially offset by an increase in~~primarily reflected lower debt redemptions and common stock dividend payments to FirstEnergy.

OE had approximately ~~$618~~$694 million of cash and temporary cash investments (which include short-term notes receivable from associated companies) and ~~approximately $199~~$210 million of short-term indebtedness as of March 31, ~~2004. Available borrowing capability under bilateral~~2005. OE has authorization from the PUCO to incur short-term debt of up to $500 million (including bank facilities ~~totaled $159~~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 as(including the utility money pool). In addition, Penn has a $25 million receivables financing facility. As of March 31, ~~2004. The~~ 2005, the facility was undrawn; it expires June 30, 2005 and is expected to be renewed.

OE ~~Companies~~and Penn had the aggregate capability to issue ~~$2.1~~approximately $1.9 billion of additional ~~first mortgage bonds (FMB)~~FMB on the basis of property additions and retired bonds ~~although unsecured~~under the terms of their respective mortgage indentures. The issuance of FMB by OE is also subject to provisions of its senior note indentures ~~entered into by OE in 2003 limit its ability to issue~~generally limiting the incurrence of additional secured debt, ~~including FMB,~~ subject to certain ~~exceptions.~~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 $650 million as of March 31, 2005. Based upon applicable earnings coverage tests ~~the~~in their respective charters, OE ~~Companies~~and Penn could issue ~~up to $3.4~~a total of $2.9 billion of preferred stock (assuming no additional debt was issued) as of March 31, ~~2004. In October 2003,~~ 2005.

OE ~~entered into~~has $409 million of credit facilities, which were unused as of March 31, 2005, consisting of a ~~syndicated $125 million 364-day revolving credit facility and a syndicated~~ $125 million three-year ~~revolving credit facility. Combined with an existing~~facility maturing in October 2006, a syndicated $250 million two-year facility ~~for OE,~~ maturing in May 2005 and bank facilities of $34 ~~million, OE's available credit facilities total $534 million, all of which were unused as of March 31, 2004.~~million. These facilities are intended to provide liquidity to meet ~~the~~OE’s short-term working capital requirements ~~of OE~~ and would be available for investment in the money pool with its regulated affiliates.

Borrowings under these facilities are conditioned on OE maintaining compliance with certain financial covenants in the agreements. OE ~~under its $125 million 364-day and $250 million two-year facilities,~~ is required to maintain a debt to total capitalization ratio of no more than 0.65 to 1 and a ~~contractually-defined~~contractually defined fixed charge coverage ratio of no less than 2 to 1. ~~OE is in compliance with these financial covenants.~~As of March 31, 2005, OE’s fixed charge coverage ratio, as defined under the credit agreements, was 6.87 to 1. OE's debt to total capitalization ratio, as defined under the credit agreements, was 0.40 to 1. The ability to draw on ~~these~~each of its facilities is also conditioned upon OE making certain representations and warranties to the lending banks prior to drawing ~~on its~~under the facilities, including a representation that there has been no material adverse change in its business, ~~its~~ condition (financial or otherwise), ~~its~~ results of operations, or ~~its~~ prospects. ~~OE's~~

None of OE’s primary credit facilities ~~do not~~ contain any provisions ~~whereby~~that either restrict its ability to borrow ~~would be restricted~~ or ~~denied, or~~accelerate repayment of outstanding ~~loans under the facilities accelerated,~~advances as a result of any change in ~~the~~its credit ~~ratings of OE by any of the nationally-recognized rating agencies. Borrowings under the~~ratings. Each primary ~~facilities do~~facility does contain "pricing grids", whereby the cost of funds borrowed under the ~~facilities~~facility is related to ~~the~~OE’s credit ~~ratings of the company borrowing the funds.~~ ratings.

OE 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. Available bank borrowings include $1.75 billion from FirstEnergy's and OE's revolving credit facilities.~~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 in the first quarter of 2005 was 2.66%.

On April 6, 2004, ~~was 1.30%. In March 2004,~~Ohio Air Quality Development Authority pollution control bonds aggregating $100 million and Ohio Water Development Authority pollution control bonds aggregating $6.45 million, respectively, were refunded. The new bonds were issued in a Dutch Auction interest rate mode, insured with municipal bond insurance and secured by FMB.

On May 16, 2005, Penn ~~completed an on-balance sheet, receivable financing transaction which allows it~~intends to ~~borrow up~~redeem 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 ~~$25 million. The borrowing rate is based on bank commercial paper rates. Penn is required to pay an annual facility fee~~the date of ~~0.40% on the entire finance limit. The facility was undrawn as of March 31, 2004. This facility matures on March 29, 2005. 55~~ ~~OE's~~redemption.

OE’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 from the rating agencies on all ~~of its~~such securities is stable. On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2 from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that the lower ratings were prompted by: "1) high consolidated leverage with significant holding company debt, 2) a degree of regulatory uncertainty in the service territories in which the company operates, 3) risks associated with investigations of the causes of the August 2003 blackout, and related securities litigation, and 4) a narrowing of the ratings range for the FirstEnergy operating utilities, given the degree to which FirstEnergy increasingly manages the utilities as a single system and the significant financial interrelationship among the subsidiaries."

On March ~~9, 2004,~~18, 2005, S&P stated that ~~the NRC's permission~~FirstEnergy’s Sammis NSR settlement was a very favorable step for FirstEnergy, although it would not immediately affect FirstEnergy’s ratings or outlook. S&P noted that it continues to ~~restart~~monitor the ~~Davis-Besse~~refueling outage at the Perry nuclear plant, ~~was positive for credit quality because it~~which includes a detailed inspection by the NRC, and that if FirstEnergy should exit the outage without significant negative findings or delays the ratings outlook would ~~positively affect cash flow by eliminating replacement power costs and "demonstrating management's ability~~be revised to overcome operational challenges." However, S&P did not change FirstEnergy's ratings or outlook because it stated that financial performance still "significantly lags expectations and management faces other operational hurdles." positive.

Cash Flows From Investing Activities

Net ~~use of~~ cash used for investing activities ~~totaled $11~~increased to $234 million in the first quarter of ~~2004, compared to net cash provided by investing activities~~2005 from $0.4 million in the first quarter of ~~$106 million for the same period of 2003.~~2004. The ~~$117 million changes in funds from investing activities~~increase resulted primarily from ~~loan payments~~a $203 million increase of loans to associated companies ~~offset~~and a $42 million increase in ~~part by lower capital expenditures.~~ property additions.

During the ~~last~~remaining three quarters of ~~2004,~~2005, capital requirements for property additions and capital leases are expected to be ~~about $183~~approximately $175 million, including ~~$46~~$19 million for nuclear fuel. OE has additional requirements of approximately ~~$68~~$120 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 ~~2004.~~2005. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. As

OE’s capital spending for the period 2005-2007 is expected to be about $667 million (excluding nuclear fuel), of ~~March 31, 2004, OE has $278~~which approximately $216 million ~~in deposits pledged~~applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to be approximately $145 million, of which about $36 million applies to 2005. During the same period, its nuclear fuel investments are expected to be reduced by approximately $126 million and $40 million, respectively, as ~~collateral to secure reimbursement obligations related to certain letters of credit supporting OE's obligations to lessors under~~ the Beaver Valley Unit 2 sale and leaseback arrangements. The deposits had previously been classified as a noncurrent asset in Other Property and Investments. OE expects to replace the cash collateralized LOC with a structure that would not require cash collateral. OE anticipates using the cash from the deposit to repay short term debt in the third quarter of 2004 and for other general corporate purposes. nuclear fuel is consumed.

Off-Balance Sheet Arrangements ~~- ------------------------------~~

Obligations not included on ~~OE's~~OE’s Consolidated Balance ~~Sheet~~Sheets primarily consist of sale and leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2. ~~As of March 31, 2004, the~~The present value of these ~~sale and leaseback~~ operating lease commitments, net of trust investments, ~~total $706 million.~~ was $688 million as of March 31, 2005.

Equity Price Risk ~~- -----------------~~

Included in ~~OE's~~OE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately ~~$218~~$244 million and ~~$209~~$248 million as of March 31, ~~2004~~2005 and December 31, ~~2003,~~2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a ~~$22~~$24 million reduction in fair value as of March 31, ~~2004. Outlook - ------- Beginning~~2005. Changes in ~~2001, OE's~~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 ~~were able to~~can select alternative energy suppliers. The OE ~~continues~~Companies continue to deliver power to residential homes and businesses through ~~its~~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. 56

Regulatory Matters Reliability Initiatives On October 15, 2003, NERC issued a Near Term Action Plan that contained recommendations for all control areas and reliability coordinators with respect to enhancing system reliability. Approximately 20 of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that are recommended for completion by summer 2004. These initiatives principally relate to changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and, preparedness and operating center training. FirstEnergy presented a detailed compliance plan to NERC, which NERC subsequently endorsed on May 7, 2004, and the various initiatives are expected to be completed no later than June 30, 2004. On February 26-27, 2004, certain FirstEnergy companies participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC to review control area operations throughout much of the United States during 2004, is an independent review to identify areas for improvement. The final audit report was completed on April 30, 2004. The report identified positive observations and included various recommendations for improvement. FirstEnergy is currently reviewing the audit results and recommendations and expects to implement those relating to summer 2004 by June 30. Based on its review thus far, FirstEnergy believes that none of the recommendations identify a need for any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that NERC 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. On March 1, 2004, certain FirstEnergy companies filed, in accordance with a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. - Canada Power System Outage Task Force interim report.

In particular, the filing addressed upgrades to FirstEnergy's control room computer hardware and software and enhancements to the training of control room operators. The PUCO will review the plan before determining the next steps, if any, in the proceeding. On April 22, 2004, FirstEnergy filed with FERC the results of the FERC-ordered independent study of part of Ohio's power grid. The study examined, among other things, the reliability of the transmission grid in critical points in the Northern Ohio area and the need, if any, for reactive power reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing the results of that study and expects to complete the implementation of recommendations relating to 2004 by this summer. Based on its review thus far, FirstEnergy believes that the study does not recommend any incremental material investment or upgrades to existing equipment. 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. With respect to each of the foregoing initiatives, FirstEnergy has requested and NERC has agreed to provide, a technical assistance team of experts to provide ongoing guidance and assistance in implementing and confirming timely and successful completion. Ohio Beginning on January 1, 2001, ~~OE's customers were able to choose their electricity suppliers.~~ 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 ~~regulated~~ generation component (plus an ~~incentive for OE customers)~~incentive), and the customer receives a generation charge from the alternative supplier. OE has continuing PLR responsibility to its franchise customers through December 31, 2005. 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 ~~megawatts (MW)~~MW of low cost supply to unaffiliated alternative suppliers who serve customers within its service area. ~~OE's competitive retail sales affiliate,~~ FES acts as an alternate supplier for a portion of the load in ~~its~~OE's franchise area. On October 21, 2003, the Ohio EUOC filed an application with the PUCO to establish generation service rates beginning January 1, 2006, in response to expressed concerns by the PUCO about price and supply uncertainty following the end of the market development period. The filing included two options: o A competitive auction, which would establish a price for generation that customers would be charged during the period covered by the auction, or 57 ~~o A~~

OE's revised Rate Stabilization Plan ~~which would extend~~extends current generation prices through 2008, ensuring adequate generation supply at ~~stable~~stabilized prices, and ~~continuing~~continues OE's support of energy efficiency and economic development efforts. ~~Under~~Other key components of the ~~first option,~~revised Rate Stabilization Plan include the following:

·	extension of the amortization period for transition costs being recovered through the RTC for OE from 2006 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 December 30, 2004, OE filed an application with the PUCO seeking tariff adjustments to recover increases of ~~the market development period - as well as the benefits of a competitive market. Customer benefits would include: customer savings by extending the current five percent discount on generation~~approximately $14 million in transmission and ancillary service costs ~~and other customer credits; maintaining current distribution base rates through 2007; market-based auctions that may be conducted annually~~beginning January 1, 2006. OE also filed an application for authority to ~~ensure that customers pay the lowest available prices; extension of our support of energy-efficiency programs~~defer costs associated with MISO Day 1, MISO Day 2, congestion fees, FERC assessment fees, and the ~~potential for continuing the program to give preferred access to nonaffiliated entities to generation capacity if shopping drops below 20%. Under the proposed plan,~~ ATSI rate increase, as applicable, from October 1, 2003 through December 31, 2005.

OE is requesting: o Extension of the transition cost amortization period from 2006 to 2007; o Deferral of interest costs on the accumulated shopping incentives and ~~other cost deferrals~~Penn record as ~~new~~ regulatory assets; and o Ability to initiate a request to increase generation rates under certain limited conditions. On January 7, 2004, the PUCO staff filed testimony on the proposed rate plan generally supporting the Rate Stabilization Plan as opposed to the competitive auction proposal. Hearings began on February 11, 2004. On February 23, 2004, after consideration of PUCO Staff comments and testimony as well as those provided by some of the intervening parties, FirstEnergy made certain modifications to the Rate Stabilization Plan. Oral arguments were held before the PUCO on April 21 and a decision is expected from the PUCO in the Spring of 2004. Pennsylvania In late 2003, the PPUC issued a Tentative Order implementing new reliability benchmarks and standards. In connection therewith, the PPUC commenced a rulemaking procedure to amend the Electric Service Reliability Regulations to implement these new benchmarks, and create additional reporting on reliability. Although neither the Tentative Order nor the Reliability Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. The comment period for both the Tentative Order and the Proposed Rulemaking Order has closed. Penn is currently awaiting the PPUC to issue a final order in both matters. The order will determine (1) the standards and benchmarks to be utilized, and (2) the details required in the quarterly and annual reports. On January 16, 2004, the PPUC initiated a formal investigation of whether Penn's "service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring" in Pennsylvania. Discovery has commenced in the proceeding and Penn's testimony is due May 14, 2004. Hearings are scheduled to begin August 3, 2004 in this investigation and the ALJ has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order by year end of 2004. Penn is unable to predict the outcome of the investigation or the impact of the PPUC order. Regulatory Assets- Regulatory assets ~~are~~ 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. ~~All~~OE’s regulatory assets as of March 31, 2005 and December 31, 2004, were $1.0 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 $250 million as of March 31, 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 ~~OE Companies'~~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 $27 million and $18 million included in Other Noncurrent Liabilities on the Consolidated Balance Sheet as of March 31, 2005 and December 31, 2004, respectively.

See Note 13 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 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 ~~expected~~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 ~~continue~~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 ~~recovered~~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 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 ~~provisions~~EPA's CAIR program. Phase II of ~~their respective transition plan and rate restructuring plans.~~the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. The OE Companies' regulatory assets are as follows: Regulatory Assets as of --------------------------------------------------------- March 31, December 31, Company 2004 2003 --------------------------------------------------------- (In millions) OE......................... $1,348 $1,450 Penn....................... 15 28 --------------------------------------------------------- Consolidated Total...... $1,363 $1,478 =================================================================== 58 ~~Environmental Matters Various federal, state and local authorities regulate OE with regard to air and water quality and other environmental matters. The effects~~future cost of compliance ~~on OE~~ with ~~regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental~~these regulations affect OE'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, OE believes it is in material compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be. OE is 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 $31,500 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. OE cannot predict what action the EPA may ~~take in the future with respect to the interim enforcement policy.~~ be substantial.

W. H. Sammis Plant

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 ~~ruling concludes~~United States signed the ~~liability phase~~Protocol in 1998 but it failed to receive the two-thirds vote of the ~~case, which deals with applicability~~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 ~~Prevention~~emissions to economic output - by 18 percent through 2012.

The OE Companies cannot currently estimate the financial impact of ~~Significant Deterioration provisions~~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 ~~Clean Air Act. The remedy phase, which~~OE Companies is ~~currently scheduled~~lower than many regional competitors due to be ready for trial beginning July 19, 2004, will address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant. In the ruling, the Court indicated that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact on the OE Companies' ~~financial condition~~diversified generation sources which include low or non-CO₂ emitting gas-fired and ~~results~~nuclear generators.

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.

Regulation of ~~operations. Management is unable to predict~~Hazardous Waste

As a result of the ~~ultimate outcome~~Resource Conservation and Recovery Act of ~~this matter and no liability has been accrued~~1976, as of March 31, 2004. The OE Companies 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. NOx reductions required by the 1990 Amendments are being achieved through combustion controlsamended, and the ~~generation~~Toxic Substances Control Act of ~~more electricity at lower-emitting plants.~~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 ~~September 1998,~~April 2000, the EPA ~~finalized regulations requiring additional NOx reductions from~~announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste.

See Note 12(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 ~~Companies' facilities.~~and its subsidiaries. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOx emissionsmost significant are contributing significantly to ozone levels in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets. Pennsylvania submitted a SIP that required compliance with the NOx budgets at the OE Companies' Pennsylvania facilities by May 1, 2003. Ohio submitted a SIP that requires compliance with the NOx budgets at the OE Companies' Ohio facilities by May 31, 2004. The OE Companies' facilities have complied with the NOx budgets in 2003 and 2004, respectively. Power Outage described below.

On August 14, 2003, various states and parts of southern Canada experienced a widespread power ~~outage. That outage~~outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. ~~On April 5, 2004, the~~The U.S. - ~~-Canada~~Canada Power System Outage Task ~~Force released its~~Force’s final report in April 2004 on ~~this outage. The final report supercedes~~ the ~~interim report that had been issued in November, 2003. In the final report, the Task Force~~outages concluded, among other things, that the problems leading to the ~~outage~~outages began in ~~FirstEnergy's~~FirstEnergy’s Ohio service ~~area. Specifically,~~area.Specifically, the final report concludes, among other things, that the initiation of the August ~~14th~~14, 2003 power ~~outage~~outages resulted from ~~the coincidence on that afternoon of several events, including,~~ 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~~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~~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 ~~14th~~14, 2003 power ~~outage~~outages and that it does not adequately address the underlying causes of the ~~outage.~~outages. FirstEnergy remains convinced that the ~~outage~~outages cannot be explained by events on any one utility's 59 system. The final report ~~contains~~contained 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations ~~relate~~related to broad industry or policy matters while one, ~~relates~~including subparts, related to activities the Task Force ~~recommends~~recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and ~~ECAR.~~other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy ~~has undertaken~~implemented several initiatives, ~~some~~both prior to and ~~some~~ since the August ~~14th~~14, 2003 power ~~outage, to enhance reliability~~outages, which ~~are~~were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and ~~believes it will complete those relating to summer 2004 by June 30 (see Regulatory Matters above).~~collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these initiatives already were in process, ~~and budgeted in 2004,~~ FirstEnergy does not believe that any incremental expenses associated with additional initiatives ~~undertaken during~~completed in 2004 ~~will have~~had a material effect on its continuing operations or financial results. FirstEnergy notes, however, that the 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. ~~Legal Matters Legal proceedings have been~~FirstEnergy has not accrued a liability as of March 31, 2005 for any expenditures in excess of those actually incurred through that date.

Three substantially similar actions were filed ~~against FirstEnergy~~ in ~~connection with, among other things, the restatements in August 2003~~various Ohio State courts by FirstEnergy and its Ohio utility subsidiaries of previously reported results, the August 14th power outage described above, and the extended outage at the Davis-Besse Nuclear Power Station. Depending upon the particular proceeding, the issues raised include alleged violations of federal securities laws, breaches of fiduciary duties under state law by FirstEnergy directors and officers, andplaintiffs 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. One case was refiled on January 12, 2004 at the PUCO. The other two cases were appealed. One case was dismissed and no further appeal was sought. In the remaining case, the Court of Appeals on March 31, 2005 affirmed the trial court’s decision dismissing the case. It is not yet known whether further appeal will be sought. In addition to the one ~~or more of~~case that was refiled at the noted events. The securities cases have been consolidated into one action pending in federal court in Akron, Ohio. The derivative actions filed in federal court likewise have been consolidated as a separate matter, also in federal court in Akron. There also are pending derivative actions in state court. FirstEnergy'sPUCO, the Ohio ~~utility subsidiaries~~Companies were ~~also~~ named as respondents in ~~two~~a regulatory ~~proceedings~~proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August ~~14th~~14, 2003 power ~~outage.~~ outages.

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 ~~instituted~~initiated against ~~them.~~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. ~~Various lawsuits, claims~~

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 ~~OE's normal business operations~~the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a second 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 ~~pending against OE,~~otherwise made subject to liability based on the ~~most significant~~above matter, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of ~~which are described above. Critical Accounting Policies - ---------------------------- OE prepares its~~operations.

See Note 12(C) to the consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of the OE Companies' assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. The OE Companies' more significant accounting policies are described below. Regulatory Accounting The OE Companies are subject to regulation that sets the prices (rates) they are permitted to charge their customers based on costs that the regulatory agencies determine the OE Companies are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Ohio and Pennsylvania, a significant amount of regulatory assets have been recorded - $1.4 billion as of March 31, 2004. OE regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Revenue Recognition The OE Companies follow the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimatedfurther details and a ~~corresponding accrual~~complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

FIN 47,“Accounting for ~~unbilled revenues is recognized. The determination~~Conditional Asset Retirement Obligations - an interpretation of ~~unbilled revenues requires management~~FASB Statement No. 143”

On March 30, 2005, the FASB issued this interpretation to ~~make estimates regarding electricity available~~clarify the scope and timing of liability recognition for ~~retail load, transmission and distribution line losses, consumption by customer class and electricity provided from alternative suppliers. 60~~ Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensionsconditional asset retirement obligations. Under this interpretation, companies are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makesrequired to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87 and SFAS 106, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to recent declines in corporate bond yields and interest rates in general, FirstEnergy reduced the assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecastsrecognize a liability for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first quarter of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Ohio Transition Cost Amortization In connection with FirstEnergy's transition plan, the PUCO determined allowable transition costs based on amounts recorded on OE's regulatory books. These costs exceeded those deferred or capitalized on OE's balance sheet prepared under GAAP since they included certain costs which have not yet been incurred. OE uses an effective interest method for amortizing its transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the transition plan for OE. In computing the transition cost amortization, OE includes only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received. Long-Lived Assets In accordance with SFAS 144, the OE Companies periodically evaluate their long-lived assets to determine whether conditions exist that would indicate that the carryingfair value of an asset ~~might not be fully recoverable. The accounting standard requires~~retirement obligation that ~~if the sum of~~is conditional on a future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, the OE Companies recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). The calculation of future cash flows is based on assumptions, estimates and judgement about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. 61 Nuclear Decommissioning In accordance with SFAS 143, the OE Companies recognize an ARO for the future decommissioning of their nuclear power plants. The ARO liability represents an estimate ofevent, if the fair value of the ~~OE Companies' current~~liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation ~~related~~is to ~~nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty~~be recognized in the ~~amount and timing of settlement of the liability. The OE Companies used an expected cash flow approach (as discussed~~first period in ~~FASB Concepts Statement No. 7)~~which sufficient information becomes available to ~~measure~~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. FirstEnergy is currently evaluating the ~~nuclear decommissioning ARO. This approach applies probability weighting~~effect this standard will have on the financial statements.

EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to ~~discounted future cash flow scenarios that reflect~~Certain Investments"

In March 2004, the EITF reached a ~~range of possible outcomes. The scenarios consider settlement of~~consensus on the ARO at the expiration of the nuclear power plants' current license and settlement based on an extended license term. New Accounting Standards and Interpretations - -------------------------------------------- FSP 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" Issued January 12, 2004, FSP 106-1 permits a sponsor of a postretirement health care plan thatapplication guidance for Issue 03-1. EITF 03-1 provides a ~~prescription drug benefit to make a one-time election to defer accounting~~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 ~~effects~~investment must be measured at fair value and the impairment loss recognized in earnings. The recognition and measurement provisions of the Medicare Act. FirstEnergy elected to defer the effects of the Medicare Act due to the lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 as a result of a February 2, 2004 plan amendment that required remeasurement of the plan's obligations. See Note 2 for a discussion of the effect of the federal subsidy and plan amendment on the consolidated financial statements. FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" In December 2003, the FASB issued a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", referred to as FIN 46R,EITF 03-1, which ~~requires the consolidation of a VIE by an enterprise if that enterprise is determined~~were to be effective for periods beginning after June 15, 2004, were delayed by the ~~primary beneficiary~~issuance of FSP EITF 03-1-1 in September 2004. During the ~~VIE. As~~period of delay, FirstEnergy will continue to evaluate its investments as required ~~OE adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types~~by existing authoritative guidance.

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,

	2005			2004

STATEMENTS OF INCOME	*(In thousands)*

OPERATING REVENUES	$	433,173		$	426,535

OPERATING EXPENSES AND TAXES:
Fuel		18,327			17,196
Purchased power		142,884			134,677
Nuclear operating costs		58,727			32,715
Other operating costs		63,573			64,027
Provision for depreciation		31,115			32,188
Amortization of regulatory assets		54,026			48,068
Deferral of new regulatory assets		(25,288	)		(18,480	)
General taxes		38,887			38,818
Income taxes		4,877			4,013
Total operating expenses and taxes		387,128			353,222

OPERATING INCOME		46,045			73,313

OTHER INCOME (net of income taxes)		4,304			11,727

NET INTEREST CHARGES:
Interest on long-term debt		27,952			32,211
Allowance for borrowed funds used during construction		411			(1,711	)
Other interest expense		6,514			6,065
Net interest charges		34,877			36,565

NET INCOME		15,472			48,475

PREFERRED STOCK DIVIDEND REQUIREMENTS		2,918			1,744

EARNINGS ON COMMON STOCK	$	12,554		$	46,731

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	15,472		$	48,475

OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gain (loss) on available for sale securities		(1,221	)		8,048
Income tax related to other comprehensive income		504			(3,296	)
Other comprehensive income (loss), net of tax		(717	)		4,752

TOTAL COMPREHENSIVE INCOME	$	14,755		$	53,227


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)
		March 31,		December 31,
		2005		2004
		*(In thousands)*
ASSETS
UTILITY PLANT:
In service		$	4,438,471	$	4,418,313
Less - Accumulated provision for depreciation			1,984,240		1,961,737
			2,454,231		2,456,576
Construction work in progress-
Electric plant			86,276		85,258
Nuclear fuel			39,655		30,827
			125,931		116,085
			2,580,162		2,572,661
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes			564,175		596,645
Nuclear plant decommissioning trusts			391,857		383,875
Long-term notes receivable from associated companies			7,222		97,489
Other			16,042		17,001
			979,296		1,095,010
CURRENT ASSETS:
Cash and cash equivalents			207		197
Receivables-
Customers	��		14,233		11,537
Associated companies			6,277		33,414
Other (less accumulated provisions of $207,000 and $293,000, respectively,
for uncollectible accounts)			92,336		152,785
Notes receivable from associated companies			--		521
Materials and supplies, at average cost			81,258		58,922
Prepayments and other			1,509		2,136
			195,820		259,512
DEFERRED CHARGES:
Goodwill			1,693,629		1,693,629
Regulatory assets			925,473		958,986
Property taxes			77,792		77,792
Other			44,648		32,875
			2,741,542		2,763,282
		$	6,496,820	$	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		$	1,281,962	$	1,281,962
Accumulated other comprehensive income			17,142		17,859
Retained earnings			511,288		553,740
Total common stockholder's equity			1,810,392		1,853,561
Preferred stock			--		96,404
Long-term debt and other long-term obligations			1,953,089		1,970,117
			3,763,481		3,920,082
CURRENT LIABILITIES:
Currently payable long-term debt			81,382		76,701
Accounts payable-
Associated companies			191,057		150,141
Other			7,593		9,271
Notes payable to associated companies			470,732		488,633
Accrued taxes			108,256		129,454
Accrued interest			34,133		22,102
Lease market valuation liability			60,200		60,200
Other			32,312		61,131
			985,665		997,633
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			535,908		540,211
Accumulated deferred investment tax credits			59,569		60,901
Asset retirement obligation			276,627		272,123
Retirement benefits			81,828		82,306
Lease market valuation liability			653,200		668,200
Other			140,542		149,009
			1,747,674		1,772,750
COMMITMENTS AND CONTINGENCIES (Note 12)
		$	6,496,820	$	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
	March 31,

	2005			2004

	*(In thousands)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	15,472		$	48,475
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		31,115			32,188
Amortization of regulatory assets		54,026			48,068
Deferral of new regulatory assets		(25,288	)		(18,480	)
Nuclear fuel and capital lease amortization		4,610			5,107
Amortization of electric service obligation		(5,451	)		(4,723	)
Deferred rents and lease market valuation liability		(53,469	)		(41,635	)
Deferred income taxes and investment tax credits, net		(4,506	)		(4,039	)
Accrued retirement benefit obligations		(478	)		5,732
Accrued compensation, net		(2,725	)		1,453
Decrease (Increase) in operating assets-
Receivables		84,890			143,766
Materials and supplies		(22,336	)		(2,355	)
Prepayments and other current assets		627			1,895
Increase (Decrease) in operating liabilities-
Accounts payable		39,238			22,387
Accrued taxes		(21,198	)		(67,926	)
Accrued interest		12,031			8,239
Other		(3,358	)		(29,788	)
Net cash provided from operating activities		103,200			148,364

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		--			80,967
Redemptions and Repayments-
Preferred stock		(97,900	)		--
Long-term debt		(330	)		(7,985	)
Short-term borrowings, net		(29,683	)		(182,167	)
Dividend Payments-
Common stock		(55,000	)		(55,000	)
Preferred stock		(2,260	)		(1,744	)
Net cash used for financing activities		(185,173	)		(165,929	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(33,683	)		(17,868	)
Loan repayments from (loans to) associated companies, net		90,788			(2,922	)
Investments in lessor notes		32,470			20,965
Contributions to nuclear decommissioning trusts		(7,256	)		(7,256	)
Other		(336	)		64
Net cash provided from (used for) investing activities		81,983			(7,017	)

Net increase (decrease) in cash and cash equivalents		10			(24,582	)
Cash and cash equivalents at beginning of period		197			24,782
Cash and cash equivalents at end of period	$	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 entities effective March 31, 2004. Adoption of FIN 46R did not have a material impact on OE's financial statements for the quarter ended March 31, 2004. See Note 2 for a discussion of Variable Interest Entities. 62 ~~THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited)~~
Three Months Ended March 31, -------------------------- 2004 2003 --------- -------- (In thousands) OPERATING REVENUES.............................................................. $ 426,535 $ 419,771 ---------- ---------- OPERATING EXPENSES AND TAXES: Fuel......................................................................... 17,196 13,769 Purchased power.............................................................. 134,677 136,345 Nuclear operating costs...................................................... 32,715 55,361 Other operating costs........................................................ 64,027 61,899 ---------- ---------- Total operation and maintenance expenses................................. 248,615 267,374 Provision for depreciation and amortization.................................. 61,776 51,357 General taxes................................................................ 38,818 39,713 Income taxes................................................................. 4,013 7,316 ---------- ---------- Total operating expenses and taxes....................................... 353,222 365,760 ---------- ---------- OPERATING INCOME................................................................ 73,313 54,011 OTHER INCOME.................................................................... 11,727 4,741 ---------- ---------- INCOME BEFORE NET INTEREST CHARGES.............................................. 85,040 58,752 ---------- ---------- NET INTEREST CHARGES: Interest on long-term debt................................................... 32,211 40,640 Allowance for borrowed funds used during construction........................ (1,711) (2,167) Other interest expense....................................................... 6,065 31 Subsidiary's preferred dividend requirements................................. -- 4,950 ---------- ---------- Net interest charges..................................................... 36,565 43,454 ---------- ---------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................ 48,475 15,298 Cumulative effect of accounting change (Net of income taxes of $30,168,000) (Note 2)...................................................... -- 42,378 ---------- ---------- NET INCOME...................................................................... 48,475 57,676 PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 1,744 (759) ---------- ----------- EARNINGS ON COMMON STOCK........................................................ $ 46,731 $ 58,435 ========== ========== ~~The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these statements.~~ 63
~~THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)~~
March 31, December 31, 2004 2003 ---------------------------- (In thousands) ASSETS UTILITY PLANT: In service..................................................................... $4,334,014 $4,232,335 Less-Accumulated provision for depreciation.................................... 1,880,144 1,857,588 ----------- ---------- 2,453,870 2,374,747 ---------- ---------- Construction work in progress- Electric plant............................................................... 95,271 159,897 Nuclear fuel................................................................. -- 21,338 ---------- ---------- 95,271 181,235 ---------- ---------- 2,549,141 2,555,982 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Investment in lessor notes..................................................... 584,950 605,915 Nuclear plant decommissioning trusts........................................... 332,303 313,621 Long-term notes receivable from associated companies........................... 97,212 107,946 Other.......................................................................... 17,818 23,636 ---------- ---------- 1,032,283 1,051,118 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents...................................................... 200 24,782 Receivables- Customers.................................................................... 8,784 10,313 Associated companies......................................................... 43,741 40,541 Other (less accumulated provisions of $1,454,000 and $1,765,000, respectively, for uncollectible accounts)................................................ 39,742 185,179 Notes receivable from associated companies..................................... 14,138 482 Materials and supplies, at average cost........................................ 52,971 50,616 Prepayments and other.......................................................... 2,616 4,511 ---------- ---------- 162,192 316,424 ---------- ---------- DEFERRED CHARGES: Regulatory assets.............................................................. 1,021,972 1,056,050 Goodwill....................................................................... 1,693,629 1,693,629 Property taxes................................................................. 77,122 77,122 Other.......................................................................... 23,599 23,123 ---------- ---------- 2,816,322 2,849,924 ---------- ---------- $6,559,938 $6,773,448 ========== ========== CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common stockholder's equity - Common stock, without par value, authorized 105,000,000 shares - 79,590,689 shares outstanding.............................................. $1,281,962 $1,281,962 Accumulated other comprehensive income....................................... 7,405 2,653 Retained earnings............................................................ 485,944 494,212 ---------- ---------- Total common stockholder's equity........................................ 1,775,311 1,778,827 Preferred stock not subject to mandatory redemption............................ 96,404 96,404 Long-term debt and other long-term obligations................................. 1,954,569 1,884,643 ---------- ---------- 3,826,284 3,759,874 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock........................... 379,924 387,414 Accounts payable- Associated companies......................................................... 268,045 245,815 Other........................................................................ 7,499 7,342 Notes payable to associated companies.......................................... 16,203 188,156 Accrued taxes................................................................. 134,596 202,522 Accrued interest............................................................... 46,111 37,872 Lease market valuation liability............................................... 60,200 60,200 Other.......................................................................... 33,337 76,722 ---------- ---------- 945,915 1,206,043 ---------- ---------- NONCURRENT LIABILITIES: Accumulated deferred income taxes.............................................. 485,976 486,048 Accumulated deferred investment tax credits.................................... 64,750 65,996 Asset retirement obligation.................................................... 259,049 254,834 Retirement benefits............................................................ 110,833 105,101 Lease market valuation liability............................................... 713,400 728,400 Other.......................................................................... 153,731 167,152 ---------- ---------- 1,787,739 1,807,531 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................ ---------- ---------- $6,559,938 $6,773,448 ========== ========== ~~The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these balance sheets.~~ 64
~~THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)~~
Three Months Ended March 31, ---------------------------- 2004 2003 --------- --------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income...................................................................... $ 48,475 $ 57,676 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization.............................. 61,776 51,357 Nuclear fuel and capital lease amortization.............................. 5,107 5,044 Other amortization....................................................... (4,723) (4,613) Deferred operating lease costs, net...................................... (41,635) (41,603) Deferred income taxes, net............................................... (2,793) 33,804 Amortization of investment tax credits................................... (1,246) (1,202) Accrued retirement benefit obligations................................... 5,732 1,797 Accrued compensation, net................................................ 1,453 2,580 Cumulative effect of accounting change (Note 2).......................... -- (72,547) Receivables.............................................................. 143,766 15,242 Materials and supplies................................................... (2,355) (128) Accounts payable......................................................... 22,387 (44,129) Accrued taxes............................................................ (67,926) 2,896 Accrued interest......................................................... 8,239 8,844 Prepayments and other current assets..................................... 1,895 1,772 Other.................................................................... (18,362) (11,970) --------- --------- Net cash provided from operating activities............................ 159,790 4,820 --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt............................................................. 80,967 -- Short-term borrowings, net................................................. -- 33,245 Redemptions and Repayments- Long-term debt............................................................. (7,985) (45,103) Short-term borrowings, net................................................. (182,167) -- Dividend Payments- Common stock............................................................... (55,000) -- Preferred stock............................................................ (1,744) (1,865) --------- --------- Net cash used for financing activities................................. (165,929) (13,723) --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................... (17,868) (31,218) Loans to associated companies, net........................................... (2,922) -- Investments in lessor notes.................................................. 20,965 19,071 Contributions to nuclear decommissioning trusts.............................. (7,256) (7,256) Other........................................................................ (11,362) (1,250) --------- --------- Net cash used for investing activities................................. (18,443) (20,653) --------- --------- Net decrease in cash and cash equivalents....................................... (24,582) (29,556) Cash and cash equivalents at beginning of period ............................... 24,782 30,382 --------- --------- Cash and cash equivalents at end of period...................................... $ 200 $ 826 ========= ========= ~~The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these statements.~~ 65
~~REPORT OF INDEPENDENT ACCOUNTANTS~~ Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of The Cleveland Electric Illuminating ~~Company~~ Company:

We have reviewed the accompanying consolidated balance sheet of The Cleveland Electric Illuminating Company and its subsidiaries as of March 31, ~~2004,~~2005, and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, ~~2004~~2005 and ~~2003.~~2004. These interim financial statements are the responsibility of the ~~Company's~~Company’s management.

We previously audited, in accordance with ~~auditing~~the standards ~~generally accepted in~~of the ~~United States of America,~~Public Company Accounting Oversight Board (United States), the consolidated balance sheet ~~and the consolidated statement of capitalization~~ as of December 31, ~~2003,~~2004, and the related consolidated statements of income, capitalization, common ~~stockholder's~~stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, ~~(not presented herein),~~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~~Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note ~~1(F)~~2(G) to those consolidated financial statements and the ~~Company's~~Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 76 to those consolidated financial statements) dated ~~February 25, 2004,~~March 7, 2005, we expressed an unqualified ~~opinion on those~~opinions thereon. The consolidated financial ~~statements.~~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 ~~condensed~~ consolidated balance sheet information as of December 31, ~~2003,~~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

May ~~7, 2004 66~~ 3, 2005

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY ~~MANAGEMENT'S~~

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 ~~them~~CEI as their power supplier. CEI provides power directly to alternative energy suppliers under ~~CEI's~~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 first quarter of ~~2004~~2005 decreased to ~~$47~~$13 million from ~~$58~~$47 million in the first quarter of ~~2003. Earnings on common stock in the first quarter of 2003 included an after-tax credit of $42 million~~2004. This decrease resulted principally from the cumulative effect of an accounting change due to the adoption of SFAS 143. Income before the cumulative effect increased to $48 million in the first quarter of 2004 from $15 million in the first quarter of 2003. higher nuclear operating and purchased power costs, partially offset by higher operating revenues.

Operating revenues increased by $7 million or 1.6% in the first quarter of ~~2004~~2005 from the same period in ~~2003.~~2004. Higher revenues resulted principally from ~~a $14~~increased retail generation sales revenue of $6 million ~~(18.3%) increase in wholesale~~(commercial - $1 million and industrial - $5 million).

Retail generation KWH sales ~~partially offset~~declined slightly and were not materially affected by a decrease in kilowatt-hour sales to retail customers. The increase in wholesale sales revenues (primarily to FES) was due to increased fossil generation (at the Mansfield Plant) available for sale to FES. Electriccustomer shopping as generation services provided by alternative suppliers ~~as a percent of total sales deliveries~~ in CEI's ~~franchise~~service area ~~increased to 42.5%~~remained relatively constant in the first quarter of ~~2004~~2005 compared to 2004. The industrial revenue increase was primarily due to higher unit prices partially offset by the effect of a 1.8% KWH sales decrease. The increase in commercial sector revenues was primarily due to a 3.3% KWH sales increase. Residential retail generation revenues were nearly unchanged for the first quarter of 2005 as compared to last year.

Wholesale sale revenues showed a slight increase of $0.4 million while reflecting the effect of a net 2.8% decrease in KWH sales. MSG wholesale sales to non-affiliated customers increased by $8.2 million (38% KWH sales increase). Under its Ohio transition plan, CEI is required to provide a low-cost generation power supply to unaffiliated alternative suppliers (see Outlook - Regulatory Matters). The MSG sales increase was partially offset by decreased sales to FES of $7.8 million (6.9% KWH decrease) due to less nuclear generation available for sale.

Revenues from ~~38.0%~~distribution throughput decreased by $5 million in the first quarter of ~~2003, resulting~~2005 compared with the corresponding quarter in ~~a 4.8%~~2004. The decrease ~~in generation retail sales~~was due to lower residential and ~~reducing generation sales revenue by~~industrial revenues ($3 million and $4 ~~million. Distribution~~million, respectively) reflecting lower composite unit prices and reduced distribution deliveries ~~increased 2.6%~~ in the first quarter of ~~2004 compared to the corresponding quarter~~2005. These impacts were partially offset by higher commercial sector sales of ~~2003, with increases in all customer sectors (residential, commercial and industrial). The $5~~$2 million ~~decrease in revenues~~resulting from ~~electricity throughput in the first quarter of 2004 from the same quarter of the prior year was due to~~increased distribution deliveries partially offset by lower ~~composite prices, offsetting the effect of the higher distribution deliveries.~~unit prices. Under the Ohio transition plan, CEI provides incentives to customers to encourage switching to alternative energy ~~providers.~~providers - $1 million of additional credits were provided to customers in the first quarter of 2005 compared with 2004. These revenue reductions are deferred for future recovery under ~~the~~CEI's transition plan and do not ~~materially~~ affect current period earnings. ~~The change~~

Other operating revenues increased by $6 million in ~~shopping~~the first quarter of 2005 compared with 2004, primarily due to increased revenues from the sales of its customer ~~sales by class (resulting in lower composite prices in 2004 compared to 2003) offset the effect of increased shopping levels and resulted in a $3 million revenue increase.~~ receivables (see Off-Balance Sheet Arrangements).

Changes in electric generation sales and distribution deliveries in the first quarter of ~~2004~~2005 from the first quarter of ~~2003~~2004 are summarized in the following table: Changes in Kilowatt-Hour Sales --------------------------------------------------- Increase (Decrease) Electric Generation: Retail.................................. (4.8)% Wholesale............................... 10.0% --------------------------------------------------- Total Electric Generation Sales........... 2.3% =================================================== Distribution Deliveries: Residential............................. 1.3% Commercial.............................. 0.9% Industrial.............................. 4.5% --------------------------------------------------- Total Distribution Deliveries............. 2.6% ===================================================

Changes in KWH Sales
Increase (Decrease)
Electric Generation:
Retail	(0.6	)%
Wholesale	(2.8	)%
Total Electric Generation Sales	(1.8	)%

Distribution Deliveries:
Residential	(3.3	)%
Commercial	5.5	%
Industrial	(2.4	)%
Total Distribution Deliveries	(0.7	)%

Operating Expenses and Taxes

Total operating expenses and taxes ~~decreased~~increased by ~~$13~~$34 million in the first quarter of ~~2004~~2005 from the first quarter of ~~2003.~~2004. The following table presents changes from the prior year by expense category. 67 Operating Expenses and Taxes - Changes ---------------------------------------------------------------- Increase (Decrease) (In millions) Fuel............................................. $ 3 Purchased

Operating Expenses and Taxes - Changes
	*(In millions)*
Increase (Decrease)
Fuel costs	$	1
Purchased power costs		8
Nuclear operating costs		26
Provision for depreciation		(1	)
Amortization of regulatory assets		6
Deferral of new regulatory assets		(7	)
Income taxes		1
Net increase in operating expenses and taxes	$	34

Higher purchased power ................................. (1) Nuclear operating costs.......................... (23) Other operating costs............................ 2 ------------------------------------------------------------ Total operation and maintenance expenses....... (19) Provision for depreciation and amortization...... 10 General taxes.................................... (1) Income taxes..................................... (3) ------------------------------------------------------------- Total operating expenses and taxes............. $(13) ============================================================= Higher fuel costs in the first quarter of ~~2004,~~2005, compared with the first quarter of ~~2003, primarily resulted from increased fossil generation (up 64%). Lower~~2004, reflected higher KWH purchased, ~~power costs reflect reduced kilowatt-hours purchased~~partially offset ~~in part~~ by ~~higher~~lower unit costs. ~~Reductions~~The increase in nuclear operating costs for the first quarter of 2005 compared to the first quarter of 2004 was primarily due to a refueling outage (including an unplanned extension) at the Perry nuclear plant and a mid-cycle inspection outage at the Davis-Besse nuclear plant in the first quarter of ~~2004,~~2005 and no scheduled outages in the first quarter of 2004.

The decrease in depreciation in the first quarter of 2005 compared with the first quarter of ~~2003 were primarily due~~2004 was attributable to ~~the reduction~~revised estimated service life assumptions for fossil generating plants. Higher amortization of regulatory assets in incremental costs associated with the Davis-Besse outage (see Davis-Besse Restoration). The increase in other operating costs resulted in part from higher employee benefit costs. The increase in depreciation and amortization charges in the first quarter of2005 as compared to 2004 ~~compared with the first quarter of 2003,~~ was primarily due to increased amortization of transition regulatory assets. Increases in the deferral of regulatory assets ~~($6 million) and lower~~in 2005 from 2004 resulted from higher shopping incentive deferrals ($31 million) and deferred interest on the shopping incentives ($5 million).

Other Income ~~taxes~~

Other income decreased by $7 million in the first quarter of 2005, compared with the first quarter of 2004, included credits from the favorable resolution of certain tax matters that had been reserved in prior periods, thus reducing CEI's reported effective income tax rate. Other Income Theprimarily due to an increase in ~~other income was principally due~~expenses related to ~~approximately $7~~the sales of customer receivables and a $2 million ~~of interest income from Shippingport which was consolidated into CEI as of December 31, 2003.~~ potential NRC fine related to the Davis-Besse Plant (see Outlook - Other Legal Proceedings).

Net Interest Charges

Net interest charges continued to trend lower, decreasing by $7$2 million in the first quarter of ~~2004~~2005 from the same quarter last year, reflecting the effects of redemptions and refinancings ~~since the end~~ of $281 million and $46 million, respectively, subsequent to the first quarter of 2003. CEI's long-term debt redemptions of $8 million during the first quarter of 2004 are expected to result in annualized savings of approximately $700,000. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, CEI recorded an after-tax credit to net income of $42 million. The cumulative effect adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component resulted in a $73 million increase to income, or $42 million net of income taxes. 2004.

Preferred Stock Dividend Requirements

Preferred stock dividend requirements increased $3by $1 million in the first quarter of ~~2004,~~2005, compared to the same period last year, due to ~~an adjustment that reduced costs~~premiums related to optional preferred stock redemptions in the first quarter of ~~2003.~~ 2005.

Capital Resources and Liquidity ~~- ------------------------------- CEI's~~

CEI’s cash requirements in ~~2004~~2005 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing ~~its~~ net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next three years, CEI expects to meet its contractual obligations with cash from operations. Thereafter, CEI expects to use a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

As of March 31, ~~2004,~~2005, CEI had ~~$200,000~~$207,000 of cash and cash equivalents, compared with ~~$25 million~~$197,000 as of December 31, ~~2003 which included a portion of the NRG settlement claim sold in January~~ 2004. The major sources ~~for~~of changes in these balances are summarized below. 68

Cash Flows ~~From~~from Operating Activities

Cash provided ~~from~~by operating activities during the first quarter of ~~2004,~~2005, compared with the first quarter of ~~2003~~2004, were as follows: Operating Cash Flows 2004 2003 ------------------------------------------------------------- (In millions)

Operating Cash Flows	2005		2004
	*(In millions)*

Cash earnings⁽¹⁾	$	13	$	72
Working capital and other		90		76
Total	$	103	$	148

⁽¹⁾Cash earnings ~~(1).................... $ 72 $ 32 Working capital~~are 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 other............ 88 (27) ------------------------------------------------------------- Total................................ $160 $ 5 ============================================================= (1) Includesmanagement with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net ~~income, depreciation~~income.

	Three Months Ended
	March 31,
Reconciliation of Cash Earnings	2005			2004
	*(In millions)*
Net Income (GAAP)	$	15		$	48
Non-Cash Charges (Credits):
Provision for depreciation		31			32
Amortization of regulatory assets		54			48
Deferral of new regulatory assets		(25	)		(18	)
Nuclear fuel and capital lease amortization		4			5
Amortization of electric service obligation		(5	)		(4	)
Deferred rents and lease market valuation liability		(53	)		(42	)
Deferred income taxes and investment tax credits, net		(4	)		(4	)
Accrued retirement benefit obligations		(1	)		6
Accrued compensation, net		(3	)		1
Cash earnings (Non-GAAP)	$	13		$	72

The $59 million decrease in cash earnings is described above and amortization, deferred operating lease costs, deferred income taxes, investment tax credits and major noncash charges. Net cash provided from operating activities increased $155 million in the first quarterunder "Results of ~~2004 from the first quarter of 2003 as~~Operations", partially offset by a ~~result of a $115~~$14 million increase from working capital and other ~~changes and a $40 million increase in~~ cash ~~earnings.~~flows. The largest ~~factor~~factors contributing to the change in working capital ~~was receiving the proceeds from the settlement of CEI's claim against NRG, Inc. for the terminated sale of four power plants.~~ and other cash flows were changes in accrued taxes, accrued interest and accounts payable, partially offset by changes in receivables.

Cash Flows ~~From~~from Financing Activities

Net cash used for financing activities increased ~~$152~~$19 million in the first quarter of ~~2004~~2005 from the first quarter of ~~2003.~~2004. The increase in funds used for financing activities ~~was~~resulted from $98 million of optional redemptions of preferred stock in the ~~result~~first quarter of ~~a $215 million net increase in short-term borrowing repayments and a $55 million increase in common stock dividends,~~2005, partially offset by ~~new financings of $81 million and reduced security~~a reduction in net debt redemptions.

CEI had ~~about $14 million~~$207,000 of cash and temporary investments ~~(which include short-term notes receivable from associated companies)~~ and approximately ~~$16~~$471 million of short-term indebtedness as of March 31, ~~2004.~~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 ~~$1.1~~$1.4 billion of additional ~~first mortgage bonds~~FMB on the basis of property additions and retired ~~bonds.~~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 $565 million as of March 31, 2005. CEI has no restrictions on the issuance of preferred stock.

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 first quarter of ~~2004~~2005 was ~~1.30%~~2.66%. ~~CEI's~~

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

On March 18, 2005, S&P stated that FirstEnergy’s Sammis NSR settlement was a very favorable step for FirstEnergy, although it would not immediately affect FirstEnergy’s ratings or outlook. S&P noted that it continues to monitor the refueling outage at the Perry nuclear plant, which includes a detailed inspection by the NRC, and that if FirstEnergy should exit the outage without significant negative findings or delays the ratings outlook would be revised to positive.

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

On June 1, 2005, CEI intends to redeem all of its ~~securities is stable. On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured debt to Baa3 from Baa2 and downgraded the senior secured debt~~40,000 outstanding shares of ~~JCP&L, Met-Ed and Penelec to Baa1 from A2. Moody's also downgraded the~~$7.35 Series C preferred stock ~~rating~~at $101.00 per share, plus accrued dividends to the date of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2 from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that the lower ratings were prompted by: "1) high consolidated leverage with significant holding company debt, 2) a degree of regulatory uncertainty in the service territories in which the company operates, 3) risks associated with investigations of the causes of the August 2003 blackout, and related securities litigation, and 4) a narrowing of the ratings range for the FirstEnergy operating utilities, given the degree to which FirstEnergy increasingly manages the utilities as a single system and the significant financial interrelationship among the subsidiaries." On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy to restart the Davis-Besse nuclear plant was positive for credit quality because it would positively affect cash flow by eliminating replacement power costs and "demonstrating management's ability to overcome operational challenges." However, S&P did not change FirstEnergy's ratings or outlook because it stated that financial performance still "significantly lags expectations and management faces other operational hurdles." redemption.

Cash Flows ~~From~~from Investing Activities

Net cash ~~used for~~provided from investing activities ~~decreased $2~~was $82 million in the first quarter of ~~2004 from~~2005 compared to cash used for investing activities of $7 million in the first quarter of ~~2003 and~~2004. The change was primarily due to ~~lower capital expenditures. 69~~ increased loan payments received from associated companies, partially offset by higher property additions.

During the ~~last~~remaining three quarters of ~~2004,~~2005, capital requirements for property additions are expected to be about ~~$106~~$85 million, including ~~$27~~$1 million for nuclear fuel. CEI has additional requirements of approximately ~~$281~~$1 million to meet sinking fund requirements for preferred stock ~~and maturing long-term debt~~ during the remainder of ~~2004.~~ 2005. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements.

CEI’s capital spending for the period 2005-2007 is expected to be about $368 million (excluding nuclear fuel) of which approximately $108 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to be approximately $75 million, of which about $10 million applies to 2005. During the same periods, CEI’s nuclear fuel investments are expected to be reduced by approximately $90 million and $27 million, respectively, as the nuclear fuel is consumed.

Off-Balance Sheet Arrangements ~~- ------------------------------~~

Obligations not included on ~~CEI's~~CEI’s Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant. As of March 31, ~~2004,~~2005, the present value of these ~~sale and leaseback~~ operating lease commitments, net of trust investments, total ~~$109~~$99 million.

CEI sells substantially all of its retail customer receivables to CFC, aits wholly owned ~~subsidiary of CEI.~~subsidiary. CFC subsequently transfers the receivables to a trust (a "qualified special purpose entity" under SFAS 140) under an asset-backed securitization agreement. This arrangement provided ~~$132~~$94 million of off-balance sheet financing as of March 31, 2004. As of March 31, 2004, off-balance sheet arrangements include certain statutory business trusts created by CEI to issue trust preferred securities in the amount of $100 million. These trusts were included in the consolidated financial statements of FirstEnergy prior to the adoption of FIN 46R effective December 31, 2003, but have subsequently been deconsolidated under FIN 46R (see Note 2 - Variable Interest Entities). The deconsolidation under FIN 46R did not result in any change in outstanding debt. 2005.

Equity Price Risk ~~- -----------------~~

Included in ~~CEI's~~CEI’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately ~~$202~~$249 million and ~~$188~~$242 million as of March 31, ~~2004~~2005 and December 31, ~~2003,~~2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a ~~$20~~$25 million reduction in fair value as of March 31, ~~2004.~~ 2005.

Outlook ~~- ------- Beginning in 2001,~~

The electric industry continues to transition to a more competitive environment and all of CEI's customers ~~were able to~~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 ~~were~~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.

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 ~~regulated~~ 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, 2005. 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 March 31, 2004 and December 2003 were $1.02 billion and $1.06 billion, respectively. All of CEI's regulatory assets are expected to continue to be recovered under the provisions of the transition 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 to unaffiliated alternative suppliers who serve customers within its service area. ~~CEI's competitive retail sales affiliate,~~ FES acts as an alternate supplier for a portion of the load in ~~its~~CEI's franchise area. On October 21, 2003, the Ohio EUOC filed an application with the PUCO to establish generation service rates beginning January 1, 2006, in response to expressed concerns by the PUCO about price and supply uncertainty following the end of the market development period. The filing included two options: o A competitive auction, which would establish a price for generation that customers would be charged during the period covered by the auction, or 70 ~~o A~~

CEI's revised Rate Stabilization Plan ~~which would extend~~extends current generation prices through 2008, ensuring adequate generation supply at ~~stable~~stabilized prices, and ~~continuing~~continues CEI's support of energy efficiency and economic development efforts. ~~Under~~Other key components of the ~~first option,~~revised Rate Stabilization Plan include the following:

·	extension of the amortization period for transition costs being recovered through the RTC from 2008 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 December 30, 2004, CEI filed an application with the PUCO seeking tariff adjustments to recover increases of approximately $16 million in transmission and ancillary service costs beginning January 1, 2006. CEI also filed an application for authority to defer costs associated with MISO Day 1, MISO Day 2, congestion fees, FERC assessment fees, and the ATSI rate increase, as applicable, from October 1, 2003 through December 31, 2005.

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 decision, CEI may be responsible for a portion of new energy market charges imposed by MISO when its energy markets begin 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. 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 ~~price~~been charged to income when incurred. CEI's regulatory assets as of March 31, 2005 and supply stability through 2008 - three years beyond the end of the market development period - as well as the benefits of a competitive market. Customer benefits would include: customer savings by extending the current five percent discount on generation costsDecember 2004 were $0.9 billion and other customer credits; maintaining current distribution base rates through 2007; market-based auctions that may be conducted annually to ensure that customers pay the lowest available prices; extension of CEI's support of energy-efficiency programs and the potential for continuing the program to give preferred access to nonaffiliated entities to generation capacity if shopping drops below 20%. Under the proposed plan,$1.0 billion, respectively. CEI is ~~requesting: o Extension of the transition cost amortization period from 2008 to mid-2009; o Deferral of interest costs on the accumulated~~deferring customer shopping incentives and ~~other cost deferrals~~interest costs as new regulatory assets; and o Ability to initiate a request to increase generation rates under certain limited conditions. On January 7, 2004, the PUCO staff filed testimony on the proposed rate plan generally supporting the Rate Stabilization Plan as opposed to the competitive auction proposal. Hearings began on February 11, 2004. On February 23, 2004, after consideration of PUCO Staff comments and testimony as well as those provided by some of the intervening parties, FirstEnergy made certain modifications to the Rate Stabilization Plan. Oral arguments were held before the PUCO on April 21 and a decision is expected from the PUCO in the Spring of 2004. Reliability Initiatives On October 15, 2003, NERC issued a Near Term Action Plan that contained recommendations for all control areas and reliability coordinators with respect to enhancing system reliability. Approximately 20 of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that are recommended for completion by summer 2004. These initiatives principally relate to changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and, preparedness and operating center training. FirstEnergy presented a detailed compliance plan to NERC, which NERC subsequently endorsed on May 7, 2004, and the various initiatives are expected to be completed no later than June 30, 2004. On February 26-27, 2004, certain FirstEnergy companies participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC to review control area operations throughout much of the United States during 2004, is an independent review to identify areas for improvement. The final audit report was completed on April 30, 2004. The report identified positive observations and included various recommendations for improvement. FirstEnergy is currently reviewing the audit results and recommendations and expects to implement those relating to summer 2004 by June 30. Based on its review thus far, FirstEnergy believes that none of the recommendations identify a need for any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that NERC 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. On March 1, 2004, certain FirstEnergy companies filed,assets in accordance with its transition and rate stabilization plans. These regulatory assets total $320 million as of March 31, 2005 and will be recovered through a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. - Canada Power System Outage Task Force interim report. In particular, the filing addressed upgrades to FirstEnergy's control room computer hardware and software and enhancementssurcharge rate equal to the ~~training~~RTC rate in effect when the transition costs have been fully recovered. Recovery of ~~control room operators. The PUCO~~the new regulatory assets will ~~review~~begin at that time and amortization of the ~~plan before determining~~regulatory assets for each accounting period will be equal to the ~~next steps, if any,~~surcharge revenue recognized during that period.

See Note 13 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.

Environmental Matters

CEI 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 CEI's determination of environmental liabilities and are accrued in the ~~proceeding. On April 22, 2004, FirstEnergy filed with FERC~~period that they are both probable and reasonably estimable.

National Ambient Air Quality Standards

In July 1997, the ~~results of the FERC-ordered independent study of part of Ohio's power grid. The study examined, among other things, the reliability of the transmission grid in critical points~~EPA promulgated changes in the ~~Northern Ohio area~~NAAQS for ozone and ~~the need, if any,~~proposed a new NAAQS for reactive power reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing the results of that study and expects to complete the implementation of recommendations relating to 2004 by this summer. Based on its review thus far, FirstEnergy believes that the study does not recommend any incremental material investment or upgrades to existing equipment. 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. 71 With respect to each of the foregoing initiatives, FirstEnergy has requested and NERC has agreed to provide, a technical assistance team of experts to provide ongoing guidance and assistance in implementing and confirming timely and successful completion. Davis-Besse Restorationfine particulate matter. On April 30, 2002, the NRC initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FENOC in the reactor vessel head near the nozzle penetration hole during a refueling outage in the first quarter of 2002. The purpose of the formal inspection process was to establish criteria for NRC oversight of the licensee's performance and to provide a record of the major regulatory and licensee actions taken, and technical issues resolved. This process led to the NRC's March 8, 2004 approval of Davis-Besse's restart. Restart activities included both hardware and management issues. In addition to refurbishment and installation work at the plant, FENOC made significant management and human performance changes with the intent of enhancing the proper safety culture throughout the workforce. The focus of activities in the first quarter of 2004 involved management and human performance issues. As a result, incremental maintenance costs declined in the first quarter of 2004 compared to the same period in 2003 as emphasis shifted to performance issues; however, replacement power costs were higher in the first quarter of 2004. The plant's generating equipment was tested in March in preparation for resumption of operation. On April 4, 2004, Davis-Besse resumed generating electricity at 100% power. Incremental costs associated with the extended Davis-Besse outage (CEI's share - 51.38%) for the first quarter of 2004 and 2003 were as follows: Three Months Ended March 31, ------------------ Increase Costs of Davis-Besse Extended Outage 2004 2003 (Decrease) - -------------------------------------------------------------------------------- (In millions) Incremental Expense Replacement power................. $64 $52 $ 12 Maintenance....................... 1 36 (35) - -------------------------------------------------------------------------------- Total......................... $65 $88 $(23) ================================================================================ Incremental Net of Tax Expense...... $38 $52 $(14) ================================================================================ Environmental Matters Various federal, state and local authorities regulate CEI with regard to air and water quality and other environmental matters. The effects of compliance on CEI with regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental regulations affect CEI'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, CEI believes it is in material compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be. CEI is 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 $31,500 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. CEI cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. CEI is 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. NOx reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998,10, 2005, the EPA finalized ~~regulations requiring additional NOx reductions from CEI's Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions~~the "Clean Air Interstate Rule" covering a total of ~~NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen~~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). 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 conclusion that such NOx emissions are contributing significantly to ozone levels in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets. Pennsylvania submitted a SIP that requiredregional 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 ~~NOx budgets~~states in which CEI operates affected facilities.

Mercury Emissions

Climate Change

In December 1997, delegates to the ~~NOx budgets at~~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.

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 ~~Ohio facilities~~diversified generation sources which include low or non-CO₂ emitting gas-fired and nuclear generators.

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 ~~May 31, 2004. CEI's facilities have complied with~~December 1, 2005 and will post the ~~NOx budgets in 2003 and 2004, respectively. 72~~ report on its web site,www.firstenergycorp.com.

Regulation of Hazardous Waste

CEI 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 ~~be held~~are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance ~~Sheets,~~Sheet as of March 31, 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. ~~CEI has~~Included in Current Liabilities are accrued liabilities aggregating approximately ~~$2.4~~$2.3 million as of March 31, ~~2004. CEI accrues environmental liabilities only when it can conclude that it is probable that an obligation~~2005.

See Note 12(B) to the consolidated financial statements for ~~such costs exists~~further details and ~~can reasonably determine the amount of such costs. Unasserted claims are reflected in CEI's determination~~a complete discussion of environmental ~~liabilities~~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 ~~accrued in the period that they are both probable and reasonably estimable. Power Outage~~ described below.

On August 14, 2003, various states and parts of southern Canada experienced a widespread power ~~outage. That outage~~outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. ~~On April 5, 2004, the~~The U.S. - ~~-Canada~~Canada Power System Outage Task ~~Force released its~~Force’s final report in April 2004 on ~~this outage. The final report supercedes~~ the ~~interim report that had been issued in November, 2003. In the final report, the Task Force~~outages concluded, among other things, that the problems leading to the ~~outage~~outages began in ~~FirstEnergy's~~FirstEnergy’s Ohio service ~~area. Specifically,~~area.Specifically, the final report concludes, among other things, that the initiation of the August ~~14th~~14, 2003 power ~~outage~~outages resulted from ~~the coincidence on that afternoon of several events, including,~~ 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~~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~~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 ~~14th~~14, 2003 power ~~outage~~outages and that it does not adequately address the underlying causes of the ~~outage.~~outages. FirstEnergy remains convinced that the ~~outage~~outages cannot be explained by events on any one utility's system. The final report ~~contains~~contained 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations ~~relate~~related to broad industry or policy matters while one, ~~relates~~including subparts, related to activities the Task Force ~~recommends~~recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and ~~ECAR.~~other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy ~~has undertaken~~implemented several initiatives, ~~some~~both prior to and ~~some~~ since the August ~~14th~~14, 2003 power ~~outage, to enhance reliability~~outages, which ~~are~~were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and ~~believes it will complete those relating to summer 2004 by June 30 (see Reliability Initiatives above).~~collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these initiatives already were in process, ~~and budgeted in 2004,~~ FirstEnergy does not believe that any incremental expenses associated with additional initiatives ~~undertaken during~~completed in 2004 ~~will have~~had a material effect on its continuing operations or financial results. FirstEnergy notes, however, that the 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. ~~Legal Matters Various lawsuits, claims~~FirstEnergy has not accrued a liability as of March 31, 2005 for any expenditures in excess of those actually incurred through that date.

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings ~~related~~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 ~~CEI's normal business operations are pending against CEI, the most significant~~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 ~~which are described herein.~~ operations.

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 ~~plant.~~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 ~~unable~~a target of the federal grand jury investigation into alleged false statements made to ~~predict the outcome of this investigation. In addition, FENOC remains subject to possible civil enforcement action by~~ the NRC in ~~connection with~~ the ~~events leading~~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 ~~Davis-Besse outage in 2002. Further, a petition was filed with~~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 April 21, 2005, the NRC ~~on March 29, 2004 by~~issued a ~~group objecting~~NOV and proposed a $5.45 million civil penalty related to the ~~NRC's restart order~~degradation of the Davis-Besse ~~Nuclear Power Station. The Petition seeks among other things, suspension~~reactor vessel head described above. Under the NRC’s letter, FENOC has ninety days to respond to this NOV. CEI has accrued the remaining liability for its share of the ~~Davis-Besse operating license.~~proposed fine of $1.8 million during the first quarter of 2005.

If it were ultimately determined that FirstEnergy or its subsidiaries has legal liability ~~or is otherwise made subject to enforcement action~~ based on ~~any of the above matters with respect to~~ the Davis-Besse ~~outage,~~head degradation, it could have a material adverse effect on ~~CEI's~~FirstEnergy's or its subsidiaries' financial condition and results of operations. ~~Legal proceedings~~

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 ~~connection with, among other things,~~September 2003 relating to the restatements in August 2003 ~~by FirstEnergy and its Ohio utility subsidiaries~~ of previously reported results ~~the August 14th power outage described above,~~by FirstEnergy and CEI, and the Davis-Besse extended outage athave become the ~~Davis-Besse Nuclear Power Station. Depending upon the particular proceeding, the~~subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised ~~include alleged violations~~during the SEC's examination of ~~federal securities laws, breaches of fiduciary duties~~FirstEnergy and the Companies under ~~state law by~~the PUHCA. Concurrent with this notification, FirstEnergy ~~directors~~received a subpoena asking for background documents and ~~officers,~~documents related to the restatements and ~~damages as~~Davis-Besse issues. On December 30, 2004, FirstEnergy received a ~~result of one or more of~~second subpoena asking for documents relating to issues raised during the noted events. The securities cases have been consolidated into one action pending in federal court in Akron, Ohio. The derivative actions filed in federal court likewise have been consolidated as a separate matter, also in federal court in Akron. There are also pending derivative actions in state court. 73 ~~FirstEnergy's Ohio utility subsidiaries were also named as respondents in two regulatory proceedings initiated at~~SEC's PUHCA examination. FirstEnergy has cooperated fully with the ~~PUCO in response~~informal inquiry and will continue to ~~complaints alleging failure to provide reasonable and adequate service stemming primarily from~~do so with the August 14th power outage. 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 instituted against them. In particular, if FirstEnergyformal investigation.

If it were ultimately determined tothat FirstEnergy or its subsidiaries have legal liability ~~in connection with these proceedings,~~or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on ~~CEI's~~FirstEnergy's or its subsidiaries' financial condition and results of operations. ~~Three substantially similar actions were filed in various Ohio state courts by plaintiffs seeking~~

See Note 12(C) to ~~represent customers who allegedly suffered damages as a result of~~ the August 14, 2003 power outage. All three cases were dismissed for lack of jurisdiction. One case was refiled at the PUCO and the other two have been appealed. Critical Accounting Policies CEI prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of CEI's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. CEI's more significant accounting policies are described below. Regulatory Accounting CEI is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine CEI is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Ohio, a significant amount of regulatory assets have been recorded - $1.02 billion as of March 31, 2004. CEI regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Revenue Recognition CEI follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimatedfurther details and a ~~corresponding accrual~~complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

On March 30, 2005, the FASB issued this interpretation to ~~make estimates regarding electricity available~~clarify the scope and timing of liability recognition for retail load, transmission and distribution line losses, consumption by customer class and electricity provided from alternative suppliers. Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensionsconditional asset retirement obligations. Under this interpretation, companies are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makesrequired to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87 and SFAS 106, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to recent declines in corporate bond 74 yields and interest rates in general, FirstEnergy reduced the assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecastsrecognize a liability for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first quarter of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Ohio Transition Cost Amortization In connection with FirstEnergy's transition plan, the PUCO determined allowable transition costs based on amounts recorded on CEI's regulatory books. These costs exceeded those deferred or capitalized on CEI's balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). CEI uses an effective interest method for amortizing its transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the transition plan for CEI. In computing the transition cost amortization, CEI includes only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received. Long-Lived Assets In accordance with SFAS 144, CEI periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carryingfair value of an asset ~~might not be fully recoverable. The accounting standard requires~~retirement obligation that ~~if the sum of~~is conditional on a future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, CEI recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). The calculation of future cash flows is based on assumptions, estimates and judgement about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. Nuclear Decommissioning In accordance with SFAS 143, CEI recognizes an ARO for the future decommissioning of its nuclear power plants. The ARO liability represents an estimate of the fair value of CEI's current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. CEI used an expected cash flow approach (as discussed in FASB Concepts Statement No. 7) to measureevent, if the fair value of the ~~nuclear decommissioning ARO. This approach applies probability weighting~~liability can be reasonably estimated. In instances where there is insufficient information to ~~discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of~~estimate the ~~ARO at~~liability, the ~~expiration of~~obligation is to be recognized in the ~~nuclear power plants' current license and settlement based on an extended license term. Goodwill In a business combination, the excess of the purchase price over the estimated~~first period in which sufficient information becomes available to estimate its fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, CEI evaluates goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, ifvalue. 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. FirstEnergy is currently evaluating the effect this standard will have 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 ~~reporting unit~~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 ~~less than its carrying~~other-than-temporary, the investment must be measured at fair value ~~(including goodwill),~~and the ~~goodwill is tested for impairment. If~~ impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to be ~~indicated CEI would recognize a loss - calculated~~effective for periods beginning after June 15, 2004, were delayed by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy will continue to evaluate its investments as ~~the difference between the implied fair value~~required by existing authoritative guidance.

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,

	2005			2004

STATEMENTS OF INCOME	*(In thousands)*

OPERATING REVENUES	$	241,755		$	235,398

OPERATING EXPENSES AND TAXES:
Fuel		12,569			10,214
Purchased power		80,156			82,408
Nuclear operating costs		59,163			42,692
Other operating costs		34,348			36,208
Provision for depreciation		14,680			14,053
Amortization of regulatory assets		34,865			33,666
Deferral of new regulatory assets		(9,424	)		(7,030	)
General taxes		14,181			14,300
Income tax benefit		(3,968	)		(1,578	)
Total operating expenses and taxes		236,570			224,933

OPERATING INCOME		5,185			10,465

OTHER INCOME (net of income taxes)		2,659			5,833

NET INTEREST CHARGES:
Interest on long-term debt		4,220			9,461
Allowance for borrowed funds used during construction		443			(1,400	)
Other interest expense		2,816			706
Net interest charges		7,479			8,767

NET INCOME		365			7,531

PREFERRED STOCK DIVIDEND REQUIREMENTS		2,211			2,211

EARNINGS (LOSS) APPLICABLE TO COMMON STOCK	$	(1,846	)	$	5,320

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME		365			7,531

OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gain (loss) on available for sale securities		(1,683	)		5,682
Income tax related to other comprehensive income		695			(2,331	)
Other comprehensive income (loss), net of tax		(988	)		3,351

TOTAL COMPREHENSIVE INCOME (LOSS)	$	(623	)	$	10,882

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

THE TOLEDO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,		December 31,
	2005		2004
	*(In thousands)*
ASSETS
UTILITY PLANT:
In service	$	1,857,720	$	1,856,478
Less - Accumulated provision for depreciation		789,915		778,864
		1,067,805		1,077,614
Construction work in progress-
Electric plant		66,405		58,535
Nuclear fuel		22,634		15,998
		89,039		74,533
		1,156,844		1,152,147
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes		178,764		190,692
Nuclear plant decommissioning trusts		305,046		297,803
Long-term notes receivable from associated companies		40,002		39,975
Other		1,835		2,031
		525,647		530,501
CURRENT ASSETS:
Cash and cash equivalents		15		15
Receivables-
Customers		6,443		4,858
Associated companies		12,180		36,570
Other		4,138		3,842
Notes receivable from associated companies		137,266		135,683
Materials and supplies, at average cost		46,769		40,280
Prepayments and other		1,206		1,150
		208,017		222,398
DEFERRED CHARGES:
Goodwill		504,522		504,522
Regulatory assets		349,297		374,814
Property taxes		24,100		24,100
Other		43,312		25,424
		921,231		928,860
	$	2,811,739	$	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		428,559		428,559
Accumulated other comprehensive income		19,051		20,039
Retained earnings		189,213		191,059
Total common stockholder's equity		832,493		835,327
Preferred stock		126,000		126,000
Long-term debt		300,131		300,299
		1,258,624		1,261,626
CURRENT LIABILITIES:
Currently payable long-term debt		90,950		90,950
Accounts payable-
Associated companies		116,930		110,047
Other		2,299		2,247
Notes payable to associated companies		394,761		429,517
Accrued taxes		31,695		46,957
Lease market valuation liability		24,600		24,600
Other		80,005		53,055
		741,240		757,373
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		221,759		221,950
Accumulated deferred investment tax credits		24,562		25,102
Retirement benefits		39,838		39,227
Asset retirement obligation		197,564		194,315
Lease market valuation liability		261,850		268,000
Other		66,302		66,313
		811,875		814,907
COMMITMENTS AND CONTINGENCIES (Note 12)
	$	2,811,739	$	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
	March 31,

	2005			2004

	*(In thousands)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	365		$	7,531
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		14,680			14,053
Amortization of regulatory assets		34,865			33,666
Deferral of new regulatory assets		(9,424	)		(7,030	)
Nuclear fuel and capital lease amortization		4,868			5,506
Deferred rents and lease market valuation liability		(15,224	)		(7,692	)
Deferred income taxes and investment tax credits, net		(1,387	)		(2,031	)
Accrued retirement benefit obligations		611			2,285
Accrued compensation, net		(1,265	)		(733	)
Decrease (Increase) in operating assets:
Receivables		41,475			20,035
Materials and supplies		(6,489	)		(1,434	)
Prepayments and other current assets		(56	)		3,384
Increase (Decrease) in operating liabilities:
Accounts payable		6,935			(6,074	)
Accrued taxes		(15,262	)		(14,085	)
Accrued interest		853			(2,280	)
Other		(1,989	)		(8,147	)
Net cash provided from operating activities		53,556			36,954

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		--			73,000
Redemptions and Repayments-
Long-term debt		--			(15,000	)
Short-term borrowings, net		(34,993	)		(93,299	)
Dividend Payments-
Preferred stock		(2,211	)		(2,211	)
Net cash used for financing activities		(37,204	)		(37,510	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(17,919	)		(8,440	)
Loan repayments from (loans to) associated companies, net		(1,610	)		2,606
Investments in lessor notes		11,928			10,280
Contributions to nuclear decommissioning trusts		(7,135	)		(7,135	)
Other		(1,616	)		1,024
Net cash used for investing activities		(16,352	)		(1,665	)

Net change in cash and cash equivalents		--			(2,221	)
Cash and cash equivalents at beginning of period		15			2,237
Cash and cash equivalents at end of period	$	15		$	16


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

Report of its goodwill and the carrying value of the goodwill. CEI's annual review was completed in the third quarter of 2003, with no impairment of goodwill indicated. The forecasts used in CEI's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on CEI's future evaluations of goodwill. As of March 31, 2004, CEI had $1.7 billion of goodwill. 75 ~~New~~Independent Registered Public Accounting Standards and Interpretations - -------------------------------------------- FSP 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" Issued January 12, 2004, FSP 106-1 permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Medicare Act. FirstEnergy elected to defer the effects of the Medicare Act due to the lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 as a result of a February 2, 2004 plan amendment that required remeasurement of the plan's obligations. See Note 2 for a discussion of the effect of the federal subsidy and plan amendment on the consolidated financial statements. FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" In December 2003, the FASB issued a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", referred to as FIN 46R, which requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, CEI adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. Adoption of FIN 46R did not have a material impact on CEI's financial statements for the quarter ended March 31, 2004. See Note 2 for a discussion of Variable Interest Entities. 76 ~~THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited)~~
Three Months Ended March 31, ------------------------- 2004 2003 -------- -------- Restated (See Note 2) (In thousands) OPERATING REVENUES.............................................................. $235,398 $231,822 -------- -------- OPERATING EXPENSES AND TAXES: Fuel......................................................................... 10,214 8,406 Purchased power.............................................................. 82,408 74,251 Nuclear operating costs...................................................... 42,692 64,555 Other operating costs........................................................ 36,208 32,932 -------- -------- Total operation and maintenance expenses................................. 171,522 180,144 Provision for depreciation and amortization.................................. 40,689 35,640 General taxes................................................................ 14,300 15,008 Income taxes (benefit)....................................................... (1,578) (4,291) -------- -------- Total operating expenses and taxes....................................... 224,933 226,501 -------- -------- OPERATING INCOME................................................................ 10,465 5,321 -------- -------- OTHER INCOME.................................................................... 5,833 3,100 -------- -------- INCOME BEFORE NET INTEREST CHARGES.............................................. 16,298 8,421 -------- -------- NET INTEREST CHARGES: Interest on long-term debt................................................... 9,461 10,888 Allowance for borrowed funds used during construction........................ (1,400) (1,306) Other interest expense (credit).............................................. 706 (532) -------- -------- Net interest charges..................................................... 8,767 9,050 -------- -------- INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE..................... 7,531 (629) Cumulative effect of accounting change (net of income taxes of $18,201,000) (Note 2)..................................................... -- 25,550 -------- -------- NET INCOME...................................................................... 7,531 24,921 PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 2,211 2,205 -------- -------- EARNINGS ON COMMON STOCK........................................................ $ 5,320 $ 22,716 ======== ======== ~~The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements.~~ 77
~~THE TOLEDO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)~~
March 31, December 31, 2004 2003 ------------------------------ (In thousands) ASSETS UTILITY PLANT: In service.................................................................... $1,801,162 $1,714,870 Less-Accumulated provision for depreciation................................... 733,161 721,754 ---------- ---------- 1,068,001 993,116 ---------- ---------- Construction work in progress- Electric plant.............................................................. 66,499 125,051 Nuclear fuel................................................................ -- 20,189 ---------- ---------- 66,499 145,240 ---------- ---------- 1,134,500 1,138,356 OTHER PROPERTY AND INVESTMENTS: Investment in lessor notes.................................................... 190,658 200,938 Nuclear plant decommissioning trusts.......................................... 255,996 240,634 Long-term notes receivable from associated companies.......................... 163,961 163,626 Other......................................................................... 2,326 2,119 ---------- ---------- 612,941 607,317 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents..................................................... 16 2,237 Receivables- Customers................................................................... 4,876 4,083 Associated companies........................................................ 21,982 29,158 Other....................................................................... 734 14,386 Notes receivable from associated companies.................................... 16,376 19,316 Materials and supplies, at average cost....................................... 36,581 35,147 Prepayments and other........................................................ 3,320 6,704 ---------- ---------- 83,885 111,031 ---------- ---------- DEFERRED CHARGES: Regulatory assets............................................................. 432,399 459,040 Goodwill...................................................................... 504,522 504,522 Property taxes................................................................ 24,443 24,443 Other......................................................................... 10,902 10,689 ---------- ---------- 972,266 998,694 ---------- ---------- $2,803,592 $2,855,398 ========== ========== 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....................................................... 428,559 428,559 Accumulated other comprehensive income...................................... 15,023 11,672 Retained earnings........................................................... 118,940 113,620 ---------- ---------- Total common stockholder's equity......................................... 758,192 749,521 Preferred stock not subject to mandatory redemption........................... 126,000 126,000 Long-term debt................................................................ 274,595 270,072 ---------- ---------- 1,158,787 1,145,593 CURRENT LIABILITIES: Currently payable long-term debt.............................................. 335,950 283,650 Short-term borrowings......................................................... -- 70,000 Accounts payable- Associated companies........................................................ 126,835 132,876 Other....................................................................... 2,784 2,816 Notes payable to associated companies......................................... 262,654 285,953 Accrued taxes................................................................ 41,518 55,604 Accrued interest.............................................................. 10,132 12,412 Lease market valuation liability.............................................. 24,600 24,600 Other......................................................................... 46,771 37,299 ---------- ---------- 851,244 905,210 ---------- ---------- NONCURRENT LIABILITIES: Accumulated deferred income taxes............................................. 204,108 201,954 Accumulated deferred investment tax credits................................... 26,668 27,200 Retirement benefits........................................................... 49,291 47,006 Asset retirement obligation................................................... 184,882 181,839 Lease market valuation liability.............................................. 286,450 292,600 Other......................................................................... 42,162 53,996 ---------- ---------- 793,561 804,595 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)............................... ---------- ---------- $2,803,592 $2,855,398 ========== ========== ~~The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these balance sheets.~~ 78
~~THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)~~
Three Months Ended March 31, -------------------------- 2004 2003 -------- -------- Restated (See Note 2) (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income...................................................................... $ 7,531 $ 24,921 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization.............................. 40,689 35,640 Nuclear fuel and capital lease amortization.............................. 5,506 2,768 Deferred operating lease costs, net...................................... (7,692) (7,672) Deferred income taxes, net............................................... (1,499) 19,130 Amortization of investment tax credits................................... (532) (514) Accrued retirement benefit obligation.................................... 2,285 771 Accrued compensation, net................................................ (733) (1,865) Cumulative effect of accounting change (Note 2).......................... -- (43,751) Receivables.............................................................. 20,035 12,249 Materials and supplies................................................... (1,434) (727) Accounts payable......................................................... (6,074) (53,917) Accrued taxes............................................................ (14,085) 6,281 Accrued interest......................................................... (2,280) (2,326) Prepayments and other current assets..................................... 3,384 (5,121) Other.................................................................... 79 (15,438) -------- -------- Net cash provided from (used for) operating activities................. 45,180 (29,571) -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt............................................................. 73,000 -- Short-term borrowings, net................................................. -- 98,392 Redemptions and Repayments- Long-term debt............................................................. (15,000) (73,600) Short-term borrowings, net................................................. (93,299) -- Dividend Payments- Preferred stock............................................................ (2,211) (2,211) -------- -------- Net cash provided from (used for) financing activities................. (37,510) 22,581 -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................... (8,440) (17,622) Loans from (to) associated companies, net.................................... 2,606 (4,445) Investment in lessor notes................................................... 10,280 17,628 Contributions to nuclear decommissioning trust............................... (7,135) (7,135) Other........................................................................ (7,202) (679) -------- -------- Net cash used for investing activities................................. (9,891) (12,253) -------- -------- Net decrease in cash and equivalents............................................ (2,221) (19,243) Cash and cash equivalents at beginning of period................................ 2,237 20,688 -------- -------- Cash and cash equivalents at end of period...................................... $ 16 $ 1,445 ======== ======== ~~The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements.~~ 79
~~REPORT OF INDEPENDENT ACCOUNTANTS~~ 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 March 31, ~~2004,~~2005, and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, ~~2004~~2005 and ~~2003.~~2004. These interim financial statements are the responsibility of the ~~Company's~~Company’s management.

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. As discussed in Note 2 to the consolidated interim financial statements, the Company has restated its previously issued consolidated interim financial statements for the three-month period ended March 31, 2003.

We previously audited, in accordance with ~~auditing~~the standards ~~generally accepted in~~of the ~~United States of America,~~Public Company Accounting Oversight Board (United States), the consolidated balance sheet ~~and the consolidated statement of capitalization~~ as of December 31, ~~2003,~~2004, and the related consolidated statements of income, capitalization, common ~~stockholder's~~stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, ~~(not presented herein),~~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~~Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note ~~1(F)~~2(G) to those consolidated financial statements and the ~~Company's~~Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 76 to those consolidated financial statements) dated ~~February 25, 2004,~~March 7, 2005, we expressed an unqualified ~~opinion on those~~opinions thereon. The consolidated financial ~~statements.~~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 ~~condensed~~ consolidated balance sheet information as of December 31, ~~2003,~~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

May ~~7, 2004 80~~ 3, 2005

THE TOLEDO EDISON COMPANY ~~MANAGEMENT'S~~

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 ~~them~~TE as their power supplier. TE provides power directly to some alternative energy suppliers under ~~TE's~~TE’s transition plan. TE has unbundled the price of electricity into its component elements --- including generation, transmission, distribution and transition charges. ~~Power~~TE’s power supply requirements ~~of TE~~ are provided by FES --- an affiliated company. Restatements of Previously Reported Quarterly Results - ----------------------------------------------------- As discussed in Note 2 to the Consolidated Financial Statements, TE's quarterly results for the first quarter of 2003 have been restated to correct the amounts reported for operating expenses and interest charges. TE's costs which were originally recorded as operating expenses and should have been capitalized to construction were $0.4 million ($0.2 million after-tax), in the first quarter of 2003. In addition, TE's interest expense was overstated by $0.9 million ($0.5 million after-tax) in the first quarter of 2003. The impact of these adjustments was not material to TE's Consolidated Balance Sheets or Consolidated Statements of Cash Flows for any quarter of 2003.

Results of Operations ~~- ---------------------~~

Earnings onapplicable to common stock in the first quarter of ~~2004~~2005 decreased to $5a loss of $2 million from ~~$23~~earnings of $5 million in the first quarter of ~~2003. Earnings on common stock~~2004. This decrease resulted primarily from higher nuclear operating costs, partially offset by higher operating revenues and lower financing costs.

Operating revenues increased by $6 million or 2.7% in the first quarter of ~~2003 included an after-tax credit of $26 million~~2005 from the ~~cumulative effect~~same period of ~~an accounting change~~2004. Higher revenues resulted principally from increased retail generation sales revenues of $10 million (industrial - $9 million and commercial - - $1 million) and wholesale sales (primarily to FES) of $4 million, partially offset by a $7 million decrease in distribution revenues.

The industrial generation revenue increase was primarily due to ~~the adoption of SFAS 143. Income before the cumulative effect increased~~higher unit prices and a 1.6% KWH sales increase. The increase in commercial sector revenues was principally due to ~~$8 million in~~a 6.1% KWH sales increase. Residential retail generation revenues were nearly unchanged for the first quarter of ~~2004 from~~2005 as compared to last year due to higher unit prices offsetting the effect of a ~~loss of $629,000 in the first quarter of 2003. Operating revenues~~4.5% KWH sales decrease. The increased ~~by $4 million or 1.5% in the first quarter of 2004 from the same period in 2003. Higher revenues resulted from an $11 million (20.3%) increase in wholesale~~commercial volume sales partially ~~offset by a decrease in retail sales revenues. The increase in sales revenues from wholesale customers (primarily to FES) was due to increased fossil generation (at~~reflected the ~~Mansfield Plant) available for sale to FES. Electric generation~~effect of lower customer shopping. Generation services provided to commercial customers by alternative suppliers as a percent of total commercial sales ~~delivered~~deliveries in TE's franchise area decreased by nearly one percentage point. The level of shopping in the industrial sector was relatively unchanged. The residential sales decrease resulted from an increase in residential shopping of 1.7 percentage points. Higher wholesale revenues reflected the effect of increased nuclear generation available for sale to ~~23.7%~~FES.

Revenues from distribution throughput decreased by $7 million in the first quarter of ~~2004~~2005 from 22% in the first quarter of 2003, resulting in a 4.0% decrease in TE's retail generation sales and a $3 million reduction in revenues. Distribution deliveries decreased 1.8% in the first quarter of 2004 compared to the corresponding quarter of ~~2003, with an increase in the industrial customer sector more than offset by reductions in the residential and commercial customer sectors.~~2004. The ~~$3 million~~ decrease ~~in revenues from electricity throughput in the first quarter of 2004 from the same quarter of the prior year~~ was due to lower industrial and residential revenues ($7 million and $1 million), principally due to lower composite ~~prices and reduced distribution deliveries.~~ unit prices. The impact of lower residential KWH sales contributed to the decrease while higher industrial sales partially offset the lower industrial sector unit prices. These revenue decreases were partially offset by a $1 million commercial revenue increase that resulted from a 4.2% sales volume increase partially offset by lower composite unit prices.

Under the Ohio transition plan, TE provides incentives to customers to encourage switching to alternative energy providers. TE’s revenues were reduced by $0.5 million for additional credits in the first quarter of 2005, compared with the same period of 2004. These revenue reductions are deferred for future recovery under ~~the~~TE’s transition plan and do not ~~materially~~ affect current period ~~earnings. The change in revenue from shopping credits was relatively flat in the first quarter of 2004 compared with the corresponding period of 2003.~~ earnings (see Regulatory Matters below).

Changes in electric generation sales and distribution deliveries in the first quarter of ~~2004~~2005 from the first quarter of ~~2003~~2004, are summarized in the following table: Changes in Kilowatt-Hour Sales ---------------------------------------------------- Increase (Decrease) Electric Generation: Retail................................ (4.0)% Wholesale............................. 21.9% ---------------------------------------------------- Total Electric Generation Sales........... 6.5% ==================================================== Distribution Deliveries: Residential............................. (5.0)% Commercial.............................. (3.6)% Industrial.............................. 1.2% ---------------------------------------------------- Total Distribution Deliveries............. (1.8)% ==================================================== 81

Changes in KWH Sales
Increase (Decrease)
Electric Generation:
Retail	1.2	%
Wholesale	18.5	%
Total Electric Generation Sales	9.2	%
Distribution Deliveries:
Residential	(1.7	)%
Commercial	4.2	%
Industrial	2.0	%
Total Distribution Deliveries	1.7	%

Operating Expenses and Taxes

Total operating expenses and taxes ~~decreased~~increased by $2$12 million in the first quarter of ~~2004~~2005 from the ~~first~~same quarter of ~~2003.~~2004. The following table presents changes from the prior year by expense category. Operating Expenses and Taxes - Changes ----------------------------------------------------------------- Increase (Decrease) (In millions) Fuel............................................. $ 2 Purchased power.................................. 8 Nuclear operating costs.......................... (22) Other operating costs............................ 3 ------------------------------------------------------------ Total operation and maintenance expenses....... (9) Provision for depreciation and amortization...... 5 General taxes.................................... (1) Income taxes..................................... 3 ------------------------------------------------------------ Total operating expenses and taxes............. $(2) =============================================================

Operating Expenses and Taxes - Changes
*Increase (Decrease)*	*(In millions)*

Fuel costs	$	2
Purchased power costs		(2	)
Nuclear operating costs		17
Other operating costs		(2	)
Provision for depreciation		1
Amortization of regulatory assets		1
Deferral of new regulatory assets		(2	)
Income taxes		(3	)
Net increase in operating expenses and taxes	$	12

Higher fuel costs in the first ~~quarter~~three months of ~~2004,~~2005, compared with the ~~first quarter~~same period of ~~2003, primarily~~2004, resulted principally from increased fossil and nuclear generation ~~(up 54%). Higher~~— up 28.1% and 29.8%, respectively. Lower purchased power costs reflect ~~additional kilowatt-hours~~lower KWH purchased, ~~and higher~~partially offset by increased unit costs. ~~Reductions in~~Increased nuclear operating costs in the first quarter of ~~2004,~~2005 compared ~~with~~to the first quarter of ~~2003,~~2004 were ~~primarily~~ due to a refueling outage (including an unplanned extension) at the ~~reduction in incremental costs associated with~~Perry nuclear plant and a mid-cycle inspection outage at the Davis-Besse outage (see Davis-Besse Restoration). The increase in other operating costs resulted from higher energy delivery costs related to increased tree trimming activities. The increase in depreciation and amortization charges of $5 millionnuclear plant in the first quarter of ~~2004, compared with~~2005 and no scheduled outages in the first quarter of ~~2003, was primarily~~2004. Other operating costs decreased due in part to lower employee benefit costs.

Depreciation charges increased by $1 million in the first three months of 2005 compared to the same period of 2004 due to an increase in depreciable property, partially offset by the effect of revised service life assumptions for fossil generating plants. Higher amortization of regulatory assets reflects the increased amortization of transition costs. Increases in deferrals of new regulatory ~~assets.~~ assets resulted from higher shopping incentives ($0.5 million) and deferred interest on the shopping incentives ($1.5 million).

Other Income

Other income ~~increased~~decreased by $3 million in the first quarter of ~~2004~~2005, compared to the same period of ~~2003 primarily~~2004, due to a decrease in interest income earned on nuclear decommissioning trust investments and the ~~absence~~accrual of ~~2003 costs~~a $1.6 million proposed NRC fine related to ~~closing Acme in Toledo, Ohio.~~ the Davis-Besse Plant (see Outlook - Other Legal Proceedings).

Net Interest Charges

Net interest charges continued to trend lower, decreasing by ~~$283,000~~$1 million in the first ~~quarter~~three months of ~~2004~~2005 from the same ~~quarter last year,~~period of 2004, reflecting redemptions and ~~refinancings since~~refinancing subsequent to the end of the first quarter of 2003. TE's long-term debt redemptions of $15 million during the first quarter of 2004 are expected to result in annualized savings of approximately $1 million. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, TE recorded an after-tax credit to net income of $26 million. The cumulative effect adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $44 million increase to income, or $26 million net of income taxes. 2004.

Capital Resources and Liquidity ~~- ------------------------------- TE's~~

TE’s cash requirements in ~~2004~~2005 for operating expenses, construction expenditures and scheduled debt maturities ~~and preferred stock redemptions~~ are expected to be met without ~~increasing its~~increasingits net debt and preferred stock outstanding. ~~Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next three years,~~Thereafter, TE expects to meet its contractual obligations with ~~cash from operations. Thereafter, TE expects to use~~ a combination of cash from operations and funds from the capital markets.

Changes in Cash Position As

There was no change as of March 31, 2005 from December 31, 2004 ~~TE had approximately $16,000 of~~in TE's cash and cash equivalents ~~compared with $2 million as~~ of ~~December 31, 2003. The major sources for changes in these balances are summarized below.~~ $15,000.

Cash Flows From Operating Activities

Cash provided from operating activities during the first quarter of ~~2004,~~2005, compared with the first quarter of ~~2003~~2004 were as follows: 82 ~~Operating Cash Flows 2004 2003 ------------------------------------------------------------- (In millions)~~

	Three Months Ended March 31,
Operating Cash Flows	2005		2004
	*(in millions)*

Cash earnings⁽¹⁾	$	28	$	46
Working capital and other		26		(9	)
Total Cash Flows from Operating Activities	$	54	$	37

⁽¹⁾Cash earnings ~~(1).................... $ 45 $ 29 Working capital~~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.TE believes that cash earnings is a useful financial measure because it provides investors and other............ -- (59) ------------------------------------------------------------- Total................................ $45 $(30) ============================================================= (1) Includesmanagement with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net ~~income, depreciation and amortization, deferred operating lease costs, deferred income taxes, investment tax credits and major noncash charges.~~ income.

	Three Months Ended March 31,
Reconciliation of Cash Earnings	2005			2004
	*(in millions)*

Net Income (GAAP)	$	--		$	8
Non-Cash Charges (Credits):
Provision for depreciation		15			14
Amortization of regulatory assets		35			34
Nuclear fuel and capital lease amortization		5			6
Deferral of new regulatory assets		(9	)		(7	)
Deferred operating lease costs, net		(15	)		(8	)
Accrued retirement benefits obligation		1			2
Accrued compensation		(2	)		(1	)
Deferred income taxes and investment tax credits, net		(2	)		(2	)
Cash earnings (Non-GAAP)	$	28		$	46

Net cash provided from operating activities increased ~~$75~~by $17 million in the first quarter of ~~2004~~2005 from the first quarter of ~~2003~~2004 as a result of a ~~$59 million increase from working capital and other changes and a $16~~$35 million increase in working capital partially offset by a $18 million decrease in cash ~~earnings.~~earnings described above and under "Results of Operations". The ~~largest factor contributing to the~~ change in working capital was ~~a $48 million change~~primarily due to changes in receivables and accounts payable. ~~The increase from the change in working capital also included receiving $12 million in proceeds from the settlement of TE's claim against NRG, Inc. for the terminated sale of its Bay Shore Plant.~~

Cash Flows From Financing Activities

Net cash used for financing activities ~~was $38 million~~decreased by $306,000 in the first quarter of ~~2004~~2005, as compared to ~~$23 million provided from financing activities in~~ the ~~first quarter of 2003. The repayments and redemptions of debt in the first quarter~~same period of 2004, ~~exceeded proceeds from issuing new long-term~~reflecting a change in net debt ~~by $35 million. In the first quarter of 2003, short-term borrowings exceeded repayments of long-term debt by $25 million.~~ redemptions.

TE had ~~$16~~$137 million of cash and temporary investments (which ~~include~~included short-term notes receivable from associated companies) and ~~$263~~$395 million of short-term indebtedness as of March 31, ~~2004.~~2005. TE ~~is currently precluded~~has authorization from ~~issuing first~~the PUCO to incur short-term debt of up to $500 million (including the utility money pool described below). As of March 31, 2005, TE had the capability to issue $907 million of additional FMB on the basis of property additions and retired bonds under the terms of its mortgage ~~bonds or preferred stock based~~indenture. Based upon applicable earnings coverage ~~tests.~~ tests, TE could issue up to $475 million of preferred stock (assuming no additional debt was issued as of March 31, 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, ~~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 first quarter of ~~2004~~2005 was ~~1.30%~~2.66%. ~~TE's~~

TE’s access to capital markets and costs of financing are dependent on the ratings of its securities and ~~that~~the securities of ~~our holding company,~~ FirstEnergy. The ratings outlook on all ~~of its~~ securities is stable. On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2 from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that the lower ratings were prompted by: "1) high consolidated leverage with significant holding company debt, 2) a degree of regulatory uncertainty in the service territories in which the company operates, 3) risks associated with investigations of the causes of the August 2003 blackout, and related securities litigation, and 4) a narrowing of the ratings range for the FirstEnergy operating utilities, given the degree to which FirstEnergy increasingly manages the utilities as a single system and the significant financial interrelationship among the subsidiaries."

On April 20, 2005, Beaver County Industrial Development Authority pollution control bonds aggregating $45 million were refunded. The new bonds were issued in a Dutch Auction interest rate mode, insured with municipal bond insurance and secured by eliminating replacement power costs and "demonstrating management's ability to overcome operational challenges." However, S&P did not change FirstEnergy's ratings or outlook because it stated that financial performance still "significantly lags expectations and management faces other operational hurdles." FMB.

Cash Flows From Investing Activities

Net cash used for investing activities ~~decreased $2~~increased by $15 million in the first quarter of ~~2004~~2005 from the ~~first quarter~~same period of ~~2003 and~~2004. This increase was primarily due to ~~lower~~increased property additions and increased loans to associated companies, partially offset by the reduction in lessor note investments.

TE’s capital ~~expenditures. During~~spending for the last three quarters of ~~2004, capital requirements for property additions are~~2005 is expected to be about ~~$42 million. TE has additional requirements of approximately $215~~$46 million ~~to meet sinking fund requirements~~(excluding $1 million for ~~preferred stock and maturing long-term debt during the remainder of 2004. The~~nuclear fuel). These cash requirements are expected to be satisfied from internal cash and short-term ~~arrangements. 83~~ 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 $54 million, of which about $8 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~~TE’s Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley Unit 2. As of March 31, ~~2004,~~2005, the present value of these ~~sale and leaseback~~ operating lease commitments, net of trust investments, ~~total $595~~totaled $566 million.

TE sells substantially all of its retail customer receivables to CFC, a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust (a ~~"qualified~~“qualified special purpose ~~entity"~~entity” under SFAS 140) under an asset-backed securitization agreement. This arrangement provided ~~$68~~$48 million of off-balance sheet financing as of March 31, ~~2004.~~ 2005.

Equity Price Risk ~~- -----------------~~

Included in ~~TE's~~TE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately ~~$156~~$194 million and ~~$145 million~~$188 as of March 31, ~~2004~~2005 and December 31, ~~2003,~~2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a ~~$16~~$19 million reduction in fair value as of March 31, ~~2004. Outlook - ------- Beginning~~2005. Changes in ~~2001,~~the fair value of these investments are recorded on OCI unless recognized as a result of sales or recognized as regulatory assets or liabilities.

Outlook

The electric industry continues to transition to a more competitive environment and all of TE's customers ~~were able to~~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.

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 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 revised 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. Other key components of the revised Rate Stabilization Plan include the following:

·	extension of the amortization period for transition costs being recovered through the RTC from mid-2007 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 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 revised Rate Stabilization Plan will take effect on January 1, 2006. The PUCO may require TE to undertake, no more often than annually, a similar competitive bid process to secure generation for the years 2007 and 2008. 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, TE filed an application with the PUCO seeking tariff adjustments to recover increases of approximately $0.1 million in transmission and ancillary service costs beginning January 1, 2006. TE also filed an application for authority to defer costs associated with MISO Day 1, MISO Day 2, congestion fees, FERC assessment fees, and the ATSI rate increase, as applicable, from October 1, 2003 through December 31, 2005. ~~Regulatory~~

TE records as 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. TE's regulatory assets as of March 31, ~~2004~~2005 and December ~~2003 are $432~~2004 were $349 million and ~~$459~~$375 million, respectively. All of TE's regulatory assets are expected to continue to be recovered under the provisions of the transition plan. 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 megawatts (MW) of low cost supply to unaffiliated alternative suppliers who serve customers within its service area. TE's competitive retail sales affiliate, FES, acts as an alternate supplier for a portion of the load in its franchise area. On October 21, 2003, the Ohio EUOC filed an application with the PUCO to establish generation service rates beginning January 1, 2006, in response to expressed concerns by the PUCO about price and supply uncertainty following the end of the market development period. The filing included two options: o A competitive auction, which would establish a price for generation that customers would be charged during the period covered by the auction, or o A Rate Stabilization Plan, which would extend current generation prices through 2008, ensuring adequate generation supply at stable prices, and continuing TE's support of energy efficiency and economic development efforts. Under the first option, an auction would be conducted to secure generation service for TE's customers. Beginning in 2006, customers would pay market prices for generation as determined by the auction. Under the Rate Stabilization Plan option, customers would have price and supply stability through 2008 - three years beyond the end of the market development period - as well as the benefits of a competitive market. Customer benefits would include:deferring customer savings by extending the current five percent discount on generation costs and other customer credits; maintaining current distribution base rates through 2007; market-based auctions that may be 84 conducted annually to ensure that customers pay the lowest available prices; extension of TE's support of energy-efficiency programs and the potential for continuing the program to give preferred access to nonaffiliated entities to generation capacity if shopping drops below 20%. Under the proposed plan, TE is requesting: o Extension of the transition cost amortization period from mid-2007 to mid-2008; o Deferral of interest costs on the accumulated shopping incentives and ~~other cost deferrals~~interest costs as new regulatory assets; and o Ability to initiate a request to increase generation rates under certain limited conditions. On January 7, 2004, the PUCO staff filed testimony on the proposed rate plan generally supporting the Rate Stabilization Plan as opposed to the competitive auction proposal. Hearings began on February 11, 2004. On February 23, 2004, after consideration of PUCO Staff comments and testimony as well as those provided by some of the intervening parties, FirstEnergy made certain modifications to the Rate Stabilization Plan. Oral arguments were held before the PUCO on April 21 and a decision is expected from the PUCO in the Spring of 2004. Reliability Initiatives On October 15, 2003, NERC issued a Near Term Action Plan that contained recommendations for all control areas and reliability coordinators with respect to enhancing system reliability. Approximately 20 of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that are recommended for completion by summer 2004. These initiatives principally relate to changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and, preparedness and operating center training. FirstEnergy presented a detailed compliance plan to NERC, which NERC subsequently endorsed on May 7, 2004, and the various initiatives are expected to be completed no later than June 30, 2004. On February 26-27, 2004, certain FirstEnergy companies participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC to review control area operations throughout much of the United States during 2004, is an independent review to identify areas for improvement. The final audit report was completed on April 30, 2004. The report identified positive observations and included various recommendations for improvement. FirstEnergy is currently reviewing the audit results and recommendations and expects to implement those relating to summer 2004 by June 30. Based on its review thus far, FirstEnergy believes that none of the recommendations identify a need for any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that NERC 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. On March 1, 2004, certain FirstEnergy companies filed,assets in accordance with its transition and rate stabilization plans. These regulatory assets total $98 million as of March 31, 2005 and will be recovered through a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. - Canada Power System Outage Task Force interim report. In particular, the filing addressed upgrades to FirstEnergy's control room computer hardware and software and enhancementssurcharge rate equal to the ~~training~~RTC rate in effect when the transition costs have been fully recovered. Recovery of ~~control room operators. The PUCO~~the new regulatory assets will ~~review~~begin at that time and amortization of the ~~plan before determining~~regulatory assets for each accounting period will be equal to the ~~next steps, if any,~~surcharge revenue recognized during that period.

See Note 13 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.

Environmental Matters

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 ~~proceeding. On April 22, 2004, FirstEnergy filed with FERC~~period that they are both probable and reasonably estimable.

National Ambient Air Quality Standards

In July 1997, the ~~results of the FERC-ordered independent study of part of Ohio's power grid. The study examined, among other things, the reliability of the transmission grid in critical points~~EPA promulgated changes in the ~~Northern Ohio area~~NAAQS for ozone and ~~the need, if any,~~proposed a new NAAQS for reactive power reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing the results of that study and expects to complete the implementation of recommendations relating to 2004 by this summer. Based on its review thus far, FirstEnergy believes that the study does not recommend any incremental material investment or upgrades to existing equipment. 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. With respect to each of the foregoing initiatives, FirstEnergy has requested and NERC has agreed to provide, a technical assistance team of experts to provide ongoing guidance and assistance in implementing and confirming timely and successful completion. 85 ~~Davis-Besse Restoration~~fine particulate matter. On April 30, 2002, the NRC initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FENOC in the reactor vessel head near the nozzle penetration hole during a refueling outage in the first quarter of 2002. The purpose of the formal inspection process was to establish criteria for NRC oversight of the licensee's performance and to provide a record of the major regulatory and licensee actions taken, and technical issues resolved. This process led to the NRC's March 8, 2004 approval of Davis-Besse's restart. Restart activities included both hardware and management issues. In addition to refurbishment and installation work at the plant, FENOC made significant management and human performance changes with the intent of enhancing the proper safety culture throughout the workforce. The focus of activities in the first quarter of 2004 involved management and human performance issues. As a result, incremental maintenance costs declined in the first quarter of 2004 compared to the same period in 2003 as emphasis shifted to performance issues; however, replacement power costs were higher in the first quarter of 2004. The plant's generating equipment was tested in March in preparation for resumption of operation. On April 4, 2004, Davis-Besse resumed generating electricity at 100% power. Incremental costs associated with the extended Davis-Besse outage (TE's share - 48.62%) for the first quarter of 2004 and 2003 were as follows: Three Months Ended March 31, ------------------- Increase Costs of Davis-Besse Extended Outage 2004 2003 (Decrease) ------------------------------------------------------------------------------ (In millions) Incremental Expense Replacement power................. $64 $52 $ 12 Maintenance....................... 1 36 (35) ----------------------------------------------------------------------------- Total......................... $65 $88 $(23) ============================================================================= Incremental Net of Tax Expense...... $38 $52 $(14) ============================================================================== Environmental Matters Various federal, state and local authorities regulate TE with regard to air and water quality and other environmental matters. The effects of compliance on TE with regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental regulations affect TE'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, TE believes it is in material compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be. TE is 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 $31,500 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. TE cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. TE is 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. NOx reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998,10, 2005, the EPA finalized ~~regulations requiring additional NOx reductions from TE's Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions~~the "Clean Air Interstate Rule" covering a total of ~~NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen~~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). 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 conclusion that such NOx emissions are contributing significantly to ozone levels in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets. Pennsylvania submitted a SIP that requiredregional 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 ~~NOx budgets~~states in which TE operates affected facilities.

Mercury Emissions

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 ~~Ohio facilities~~diversified generation sources which include low or non-CO₂ emitting gas-fired and nuclear generators.

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 ~~May 31, 2004. TE's facilities have complied with~~December 1, 2005 and will post the ~~NOx budgets in 2003 and 2004, respectively.~~ report on its website,www.firstenergycorp.com.

Regulation of Hazardous Waste

TE 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 ~~be held~~are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance ~~Sheets,~~Sheet as of March 31, 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. ~~TE has~~Included in Current Liabilities are accrued liabilities aggregating 86 approximately $0.2 million as of March 31, ~~2004.~~2005. TE accrues environmental liabilities only when it ~~can conclude~~concludes that it is probable that it has an obligation for such costs ~~exists~~ 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. ~~Power Outage~~

See Note 12(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 a widespread power ~~outage. That outage~~outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. ~~On April 5, 2004, the~~The U.S. - ~~-Canada~~Canada Power System Outage Task ~~Force released its~~Force’s final report in April 2004 on ~~this outage. The final report supercedes~~ the ~~interim report that had been issued in November, 2003. In the final report, the Task Force~~outages concluded, among other things, that the problems leading to the ~~outage~~outages began in ~~FirstEnergy's~~FirstEnergy’s Ohio service ~~area. Specifically,~~area.Specifically, the final report concludes, among other things, that the initiation of the August ~~14th~~14, 2003 power ~~outage~~outages resulted from ~~the coincidence on that afternoon of several events, including,~~ 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~~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~~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 ~~14th~~14, 2003 power ~~outage~~outages and that it does not adequately address the underlying causes of the ~~outage.~~outages. FirstEnergy remains convinced that the ~~outage~~outages cannot be explained by events on any one utility's system. The final report ~~contains~~contained 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations ~~relate~~related to broad industry or policy matters while one, ~~relates~~including subparts, related to activities the Task Force ~~recommends~~recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and ~~ECAR.~~other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy ~~has undertaken~~implemented several initiatives, ~~some~~both prior to and ~~some~~ since the August ~~14th~~14, 2003 power ~~outage, to enhance reliability~~outages, which ~~are~~were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and ~~believes it will complete those relating to summer 2004 by June 30 (see Reliability Initiatives above).~~collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these initiatives already were in process, ~~and budgeted in 2004,~~ FirstEnergy does not believe that any incremental expenses associated with additional initiatives ~~undertaken during~~completed in 2004 ~~will have~~had a material effect on its continuing operations or financial results. ~~First Energy~~FirstEnergy notes, however, that the 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. ~~Legal Matters Various lawsuits, claims~~FirstEnergy has not accrued a liability as of March 31, 2005 for any expenditures in excess of those actually incurred through that date.

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings ~~related~~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 ~~TE's normal business operations are pending against TE, the most significant~~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 ~~which are described herein.~~ operations.

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 ~~plant.~~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 ~~unable~~a target of the federal grand jury investigation into alleged false statements made to ~~predict the outcome of this investigation. In addition, FENOC remains subject to possible civil enforcement action by~~ the NRC in ~~connection with~~ the ~~events leading~~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 ~~Davis Besse outage in 2002. Further, a petition was filed with~~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 April 21, 2005, the NRC ~~on March 29, 2004 by~~issued a ~~group objecting~~NOV and proposed a $5.45 million civil penalty related to the ~~NRC's restart order~~degradation of the Davis-Besse ~~Nuclear Power Station. The Petition seeks among other things, suspension~~reactor vessel head described above. Under the NRC’s letter, FENOC has ninety days to respond to this NOV. TE has accrued the remaining liability for its share of the ~~Davis-Besse operating license.~~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 ~~or is otherwise made subject to enforcement action~~ based on ~~any of the above matters with respect to~~ the Davis-Besse ~~outage,~~head degradation, it could have a material adverse effect on ~~TE's~~FirstEnergy's or any of its subsidiaries' financial condition and results of operations. ~~Legal proceedings~~

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 ~~connection with, among other things,~~September 2003 relating to the restatements in August 2003 ~~by FirstEnergy and its Ohio utility subsidiaries~~ of previously reported results ~~the August 14th power outage described above,~~by FirstEnergy and TE, and the Davis-Besse extended outage, athave become the ~~Davis-Besse Nuclear Power Station. Depending upon the particular proceeding, the~~subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised ~~include alleged violations~~during the SEC's examination of ~~federal securities laws, breaches of fiduciary duties~~FirstEnergy and the Companies under ~~state law by~~the PUHCA. Concurrent with this notification, FirstEnergy ~~directors~~received a subpoena asking for background documents and ~~officers,~~documents related to the restatements and ~~damages as~~Davis-Besse issues. On December 30, 2004, FirstEnergy received a ~~result of one or more of~~second subpoena asking for documents relating to issues raised during the noted events. The securities cases have been consolidated into one action pending in federal court in Akron, Ohio. The derivative actions filed in federal court likewise have been consolidated as a separate matter, also in federal court in Akron. There are also pending derivative actions in state court. FirstEnergy's Ohio utility subsidiaries were also named as respondents in two regulatory proceedings initiated atSEC's PUHCA examination. FirstEnergy has cooperated fully with the ~~PUCO in response~~informal inquiry and will continue to ~~complaints alleging failure to provide reasonable and adequate service stemming primarily from~~do so with the August 14th power outage. 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 instituted against them. In particular, if FirstEnergyformal investigation.

If it were ultimately determined tothat FirstEnergy or its subsidiaries have legal liability ~~in connection with these proceedings,~~or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on ~~TE's~~FirstEnergy's or its subsidiaries' financial condition and results of operations. 87 ~~Three substantially similar actions were filed in various Ohio state courts by plaintiffs seeking~~

See Note 12(C) to ~~represent customers who allegedly suffered damages as a result of~~ the August 14, 2003 power outage. All three cases were dismissed for lack of jurisdiction. One case was refiled at the PUCO and the other two have been appealed. Critical Accounting Policies - ---------------------------- TE prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of TE's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. TE's more significant accounting policies are described below. Regulatory Accounting TE is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine TE is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Ohio, a significant amount of regulatory assets have been recorded - $432 million as of March 31, 2004. TE regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Revenue Recognition TE follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimatedfurther details and a ~~corresponding accrual~~complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

On March 30, 2005, the FASB issued this interpretation to ~~make estimates regarding electricity available~~clarify the scope and timing of liability recognition for retail load, transmission and distribution line losses, consumption by customer class and electricity provided from alternative suppliers. Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensionsconditional asset retirement obligations. Under this interpretation, companies are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makesrequired to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87 and SFAS 106, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to recent declines in corporate bond yields and interest rates in general, FirstEnergy reduced the assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecastsrecognize a liability for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first quarter of 2004 were computed assuming a 9.0% rate of return on plan assets 88 based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Ohio Transition Cost Amortization In connection with FirstEnergy's transition plan, the PUCO determined allowable transition costs based on amounts recorded on TE's regulatory books. These costs exceeded those deferred or capitalized on TE's balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). TE uses an effective interest method for amortizing its transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the transition plan for TE. In computing the transition cost amortization, TE includes only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received. Long-Lived Assets In accordance with SFAS 144, TE periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carryingfair value of an asset ~~might not be fully recoverable. The accounting standard requires~~retirement obligation that ~~if the sum of~~is conditional on a future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, TE recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). The calculation of future cash flows is based on assumptions, estimates and judgement about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. Nuclear Decommissioning In accordance with SFAS 143, TE recognizes an ARO for the future decommissioning of its nuclear power plants. The ARO liability represents an estimate of the fair value of TE's current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. TE used an expected cash flow approach (as discussed in FASB Concepts Statement No. 7) to measureevent, if the fair value of the ~~nuclear decommissioning ARO. This approach applies probability weighting~~liability can be reasonably estimated. In instances where there is insufficient information to ~~discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of~~estimate the ~~ARO at~~liability, the ~~expiration of~~obligation is to be recognized in the ~~nuclear power plants' current license and settlement based on an extended license term. Goodwill In a business combination, the excess of the purchase price over the estimated~~first period in which sufficient information becomes available to estimate its fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, TE evaluates goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, ifvalue. 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. FirstEnergy is currently evaluating the effect this standard will have 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 ~~reporting unit~~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 ~~less than its carrying~~other-than-temporary, the investment must be measured at fair value ~~(including goodwill),~~and the ~~goodwill is tested for impairment. If~~ impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to be ~~indicated, TE would recognize a loss - calculated~~effective for periods beginning after June 15, 2004, were delayed by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy will continue to evaluate its investments as ~~the difference between the implied fair value~~required by existing authoritative guidance.

PENNSYLVANIA POWER COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,

	2005			2004

STATEMENTS OF INCOME	*(In thousands)*

OPERATING REVENUES	$	134,484		$	142,623

OPERATING EXPENSES AND TAXES:
Fuel		5,620			6,206
Purchased power		46,980			48,508
Nuclear operating costs		19,948			18,623
Other operating costs		12,768			13,685
Provision for depreciation		3,694			3,362
Amortization of regulatory assets		9,882			10,076
General taxes		6,472			6,634
Income taxes		12,421			15,038
Total operating expenses and taxes		117,785			122,132

OPERATING INCOME		16,699			20,491

OTHER INCOME (EXPENSE) (net of income taxes)		(745	)		982

NET INTEREST CHARGES:
Interest expense		2,319			2,725
Allowance for borrowed funds used during construction		(1,367	)		(922	)
Net interest charges		952			1,803

NET INCOME		15,002			19,670

PREFERRED STOCK DIVIDEND REQUIREMENTS		640			640

EARNINGS ON COMMON STOCK	$	14,362		$	19,030

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	15,002		$	19,670

OTHER COMPREHENSIVE INCOME		--			--

TOTAL COMPREHENSIVE INCOME	$	15,002		$	19,670


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

PENNSYLVANIA POWER COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2005			2004
	*(In thousands)*
ASSETS
UTILITY PLANT:
In service	$	873,780		$	866,303
Less - Accumulated provision for depreciation		364,354			356,020
		509,426			510,283
Construction work in progress-
Electric plant		121,145			104,366
Nuclear fuel		7,647			3,362
		128,792			107,728
		638,218			618,011
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		142,317			143,062
Long-term notes receivable from associated companies		32,890			32,985
Other		530			722
		175,737			176,769
CURRENT ASSETS:
Cash and cash equivalents		38			38
Notes receivable from associated companies		545			431
Receivables-
Customers (less accumulated provisions of $940,000 and $888,000,
respectively, for uncollectible accounts)		42,984			44,282
Associated companies		13,019			23,016
Other		1,059			1,656
Materials and supplies, at average cost		37,705			37,923
Prepayments and other		22,405			8,924
		117,755			116,270

DEFERRED CHARGES		9,921			10,106
	$	941,631		$	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		64,690			64,690
Accumulated other comprehensive loss		(13,706	)		(13,706	)
Retained earnings		94,057			87,695
Total common stockholder's equity		333,741			327,379
Preferred stock		39,105			39,105
Long-term debt and other long-term obligations		121,889			133,887
		494,735			500,371
CURRENT LIABILITIES:
Currently payable long-term debt		38,524			26,524
Accounts payable-
Associated companies		43,569			46,368
Other		1,345			1,436
Notes payable to associated companies		10,644			11,852
Accrued taxes		25,475			14,055
Accrued interest		1,614			1,872
Other		9,156			8,802
		130,327			110,909
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		89,060			93,418
Accumulated deferred investment tax credits		3,150			3,222
Asset retirement obligation		140,560			138,284
Retirement benefits		50,116			49,834
Regulatory liabilities		26,523			18,454
Other		7,160			6,664
		316,569			309,876
COMMITMENTS AND CONTINGENCIES (Note 12)
	$	941,631		$	921,156

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

PENNSYLVANIA POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31,

	2005			2004

	*(In thousands)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	15,002		$	19,670
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		3,694			3,362
Amortization of regulatory assets		9,882			10,076
Nuclear fuel and other amortization		4,140			4,565
Deferred income taxes and investment tax credits, net		(2,311	)		(1,806	)
Decrease (Increase) in operating assets-
Receivables		11,892			(214	)
Materials and supplies		218			(1,075	)
Prepayments and other current assets		(13,481	)		(13,333	)
Increase (Decrease) in operating liabilities-
Accounts payable		(2,890	)		3,740
Accrued taxes		11,420			8,809
Accrued interest		(258	)		(1,956	)
Other		778			2,857
Net cash provided from operating activities		38,086			34,695

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		--			29,084
Redemptions and Repayments-
Long-term debt		--			(42,302	)
Short-term borrowings, net		(1,208	)		--
Dividend Payments-
Common stock		(8,000	)		(8,000	)
Preferred stock		(640	)		(640	)
Net cash used for financing activities		(9,848	)		(21,858	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(28,522	)		(13,998	)
Contributions to nuclear decommissioning trusts		(399	)		(399	)
Loans to associated companies		(19	)		(116	)
Other		702			1,676
Net cash used for investing activities		(28,238	)		(12,837	)

Net change in cash and cash equivalents		--			--
Cash and cash equivalents at beginning of period		38			40
Cash and cash equivalents at end of period	$	38		$	40

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

Report of its goodwill and the carrying value of the goodwill. TE's annual review was completed in the third quarter of 2003, with no impairment of goodwill indicated. The forecasts used in TE's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on TE's future evaluations of goodwill. As of March 31, 2004, TE had $505 million of goodwill. 89 ~~New~~Independent Registered Public Accounting Standards and Interpretations FSP 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" Issued January 12, 2004, FSP 106-1 permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Medicare Act. FirstEnergy elected to defer the effects of the Medicare Act due to the lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 as a result of a February 2, 2004 plan amendment that required remeasurement of the plan's obligations. See Note 2 for a discussion of the effect of the federal subsidy and plan amendment on the consolidated financial statements. FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" In December 2003, the FASB issued a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", referred to as FIN 46R, which requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, TE adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. Adoption of FIN 46R did not have a material impact on TE's financial statements for the quarter ended March 31, 2004. See Note 2 for a discussion of Variable Interest Entities. 90 ~~PENNSYLVANIA POWER COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited)~~
Three Months Ended March 31, ------------------------- 2004 2003 --------- -------- (In thousands) OPERATING REVENUES.............................................................. $142,623 $128,343 -------- -------- OPERATING EXPENSES AND TAXES: Fuel......................................................................... 6,206 4,713 Purchased power.............................................................. 48,508 44,066 Nuclear operating costs...................................................... 18,623 46,929 Other operating costs........................................................ 13,685 16,550 -------- -------- Total operation and maintenance expenses................................. 87,022 112,258 Provision for depreciation and amortization.................................. 13,438 13,265 General taxes................................................................ 6,634 6,179 Income taxes (benefit)....................................................... 15,038 (1,479) -------- -------- Total operating expenses and taxes....................................... 122,132 130,223 -------- -------- OPERATING INCOME (LOSS)......................................................... 20,491 (1,880) OTHER INCOME.................................................................... 982 561 -------- -------- INCOME (LOSS) BEFORE NET INTEREST CHARGES....................................... 21,473 (1,319) -------- -------- NET INTEREST CHARGES: Interest expense............................................................. 2,725 4,064 Allowance for borrowed funds used during construction........................ (922) (629) -------- -------- Net interest charges..................................................... 1,803 3,435 -------- -------- INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE..................... 19,670 (4,754) Cumulative effect of accounting change (net of income taxes of $7,532,000) (Note 2) -- 10,618 -------- -------- NET INCOME...................................................................... 19,670 5,864 PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 640 912 -------- -------- EARNINGS ON COMMON STOCK........................................................ $ 19,030 $ 4,952 ======== ======== ~~The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of these statements.~~ 91
~~PENNSYLVANIA POWER COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)~~
March 31, December 31, 2004 2003 --------------------------- (In thousands) ASSETS UTILITY PLANT: In service........................................................................ $820,643 $808,637 Less-Accumulated provision for depreciation....................................... 332,363 324,710 -------- -------- 488,280 483,927 -------- -------- Construction work in progress- Electric plant................................................................. 69,521 68,091 Nuclear fuel................................................................... 360 360 -------- -------- 69,881 68,451 -------- -------- 558,161 552,378 -------- -------- OTHER PROPERTY AND INVESTMENTS: Nuclear plant decommissioning trusts ............................................. 137,840 133,867 Long-term notes receivable from associated companies.............................. 33,136 39,179 Other............................................................................. 836 2,195 -------- -------- 171,812 175,241 -------- -------- CURRENT ASSETS: Cash and cash equivalents......................................................... 40 40 Notes receivable from associated companies........................................ 6,558 399 Receivables- Customers (less accumulated provisions of $816,000 and $769,000, respectively, for uncollectible accounts).................................... 46,129 44,861 Associated companies........................................................... 24,492 24,965 Other.......................................................................... 466 1,047 Materials and supplies, at average cost........................................... 34,993 33,918 Prepayments....................................................................... 22,716 9,383 -------- -------- 135,394 114,613 -------- -------- DEFERRED CHARGES: Regulatory assets................................................................. 15,155 27,513 Other............................................................................. 9,348 9,634 -------- -------- 24,503 37,147 -------- -------- $889,870 $879,379 ======== ======== 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.......................................................... (310) (310) Accumulated other comprehensive loss........................................... (11,783) (11,783) Retained earnings.............................................................. 65,209 54,179 -------- -------- Total common stockholder's equity.......................................... 241,816 230,786 Preferred stock not subject to mandatory redemption............................... 39,105 39,105 Long-term debt and other long-term obligations.................................... 130,397 130,358 -------- -------- 411,318 400,249 -------- -------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock.............................. 52,224 93,474 Accounts payable- Associated companies........................................................... 43,895 40,172 Other.......................................................................... 1,311 1,294 Notes payable to associated companies............................................. 40,418 11,334 Accrued taxes..................................................................... 35,900 27,091 Accrued interest.................................................................. 2,440 4,396 Other............................................................................. 9,557 8,444 -------- -------- 185,745 186,205 -------- -------- NONCURRENT LIABILITIES: Accumulated deferred income taxes................................................. 93,894 97,871 Accumulated deferred investment tax credits....................................... 3,443 3,516 Asset retirement obligation....................................................... 131,678 129,546 Retirement benefits............................................................... 55,830 54,057 Other............................................................................. 7,962 7,935 -------- -------- 292,807 292,925 -------- -------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................ -------- -------- $889,870 $879,379 ======== ======== ~~The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of these balance sheets.~~ 92
~~PENNSYLVANIA POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)~~
Three Months Ended March 31, --------------------------- 2004 2003 --------- -------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income...................................................................... $ 19,670 $ 5,864 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization................................ 13,438 13,265 Nuclear fuel and lease amortization........................................ 4,565 3,583 Deferred income taxes, net................................................. (1,231) 6,122 Amortization of investment tax credits..................................... (575) (620) Cumulative effect of accounting change (Note 2)............................ -- (18,150) Receivables................................................................ (214) 17,262 Materials and supplies..................................................... (1,075) (431) Accounts payable........................................................... 3,740 27,844 Accrued taxes.............................................................. 8,809 4,271 Accrued interest........................................................... (1,956) (2,009) Prepayments and other current assets....................................... (13,334) (16,288) Asset retirement obligation, net........................................... 3,195 (980) Other...................................................................... 3,237 600 -------- -------- Net cash provided from operating activities............................ 38,269 40,333 -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net................................................. 29,084 -- Redemptions and Repayments- Long-term debt............................................................. (42,302) (16) Dividend Payments- Common stock............................................................... (8,000) (13,000) Preferred stock............................................................ (640) (912) -------- -------- Net cash used for financing activities................................. (21,858) (13,928) -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................... (13,998) (31,054) Contributions to nuclear decommissioning trusts.............................. (399) (399) Loans from (to) associated companies, net.................................... (116) 4,921 Other........................................................................ (1,898) 732 -------- -------- Net cash used for investing activities................................. (16,411) (25,800) -------- -------- Net change in cash and cash equivalents......................................... -- 605 Cash and cash equivalents at beginning of period................................ 40 1,222 -------- -------- Cash and cash equivalents at end of period...................................... $ 40 $ 1,827 ======== ======== ~~The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of these statements.~~ 93
~~REPORT OF INDEPENDENT ACCOUNTANTS~~ 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 March 31, ~~2004,~~2005, and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, ~~2004~~2005 and ~~2003.~~2004. These interim financial statements are the responsibility of the ~~Company's~~Company’s management.

We previously audited, in accordance with ~~auditing~~the standards ~~generally accepted in~~of the ~~United States of America,~~Public Company Accounting Oversight Board (United States), the consolidated balance sheet ~~and the statement of capitalization~~ as of December 31, ~~2003,~~2004, and the related consolidated statements of income, capitalization, common ~~stockholders'~~stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, ~~(not presented herein),~~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~~Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note ~~1(E)~~2(G) to those consolidated financial statements) dated ~~February 25, 2004,~~March 7, 2005, we expressed an unqualified ~~opinion on those~~opinions thereon. The consolidated financial ~~statements.~~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 ~~condensed~~consolidated balance sheet information as of December 31, ~~2003,~~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

May ~~7, 2004 94~~ 3, 2005

PENNSYLVANIA POWER COMPANY ~~MANAGEMENT'S~~

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 itPenn 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. ~~Penn's wholly owned subsidiary, Penn Power Funding LLC, began operations on March 30, 2004.~~

Results of Operations ~~- ---------------------~~

Earnings on common stock in the first quarter of ~~2004 increased~~2005 decreased to ~~$19~~$14 million from $5$19 million in the first quarter of ~~2003. Earnings on common stock~~2004. The lower earnings resulted from decreased operating revenues, partially offset by lower operating expenses and taxes and lower net interest charges.

Operating revenues decreased by $8 million, or 6%, in the first quarter of 2003 included an after-tax credit of $11 million from the cumulative effect of an accounting change due to the adoption of SFAS 143. Income before the cumulative effect was $20 million in the first three months of 2004,2005 as compared to a loss of $5 million for the same period of 2003. Improved results in the first quarter of 2004 reflect higher operating revenues and lower operating expenses -- primarily nuclear operating costs. Operating revenues increased by $14 million or 11.1% in the first quarter of 2004 compared with ~~the same period in 2003. The higher revenues primarily resulted from increased wholesale revenues of $11 million due to increased nuclear generation available for sale to FES in~~ the first quarter of 2004. ~~Retail~~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 generation sales revenues ~~increased~~of $3 million resulted from higher commercial and industrial sales of $1 million and $2 million, respectively, as a result of higher composite unit prices and increased KWH sales. The increased sales reflected an improving service area economy including higher sales to the steel industry. These increases were partially offset by a $0.2 million residential revenues decrease reflecting lower sales volume (0.8%) and unit prices.

A $2 million reduction in distribution throughput revenues was primarily ~~from~~due to lower unit prices, partially offset by higher KWH deliveries to commercial and industrial customers. The lower unit prices are attributable to changes in Penn's CTC rate schedules in April 2004 as a 3.1% increase in generation sales. Distribution deliveries increased 3.1% in the first quarter of 2004 compared with the corresponding quarter of 2003, with increases in all customer sectors. The change in revenues from electricity throughput was flat with the effectresult of the ~~volume increase offset by lower composite prices.~~ annual CTC reconciliation.

Changes in electric generation ~~sales~~ and distribution deliveries in the first quarter of ~~2004~~2005 from the same quarter ~~of 2003~~in 2004 are summarized in the following table: Changes in Kilowatt-Hour Sales --------------------------------------------------- Increase (Decrease) Electric Generation: Retail.................................. 3.1% Wholesale............................... 32.1% --------------------------------------------------- Total Electric Generation Sales........... 18.3% =================================================== Distribution Deliveries: Residential............................. 3.1% Commercial.............................. 0.5% Industrial.............................. 5.4% --------------------------------------------------- Total Distribution Deliveries............. 3.1% ===================================================

Changes in KWH Sales
*Increase (Decrease)*
Electric Generation:
Retail	0.7	%
Wholesale	(7.9	)%
Total Electric Generation Sales	(4.3	)%

Distribution Deliveries:
Residential	(0.8	)%
Commercial	2.1	%
Industrial	1.3	%
Total Distribution Deliveries	0.7	%

Operating Expenses and Taxes

Total operating expenses and taxes decreased by $8$4 million in the first quarter of ~~2004~~2005 from the first quarter of 2003. The following table presents changes from the prior year by expense category. Operating Expenses and Taxes - Changes ------------------------------------------------------------ Increase (Decrease) (In millions) Fuel............................................ $ 2 Purchased power ................................ 4 Nuclear operating costs......................... (28) Other operating costs........................... (3) ------------------------------------------------------------ Total operation and maintenance expenses..... (25) Provision for depreciation and amortization..... -- General taxes................................... -- Income taxes.................................... 17 ------------------------------------------------------------ Total operating expenses and taxes........... $ (8) ============================================================ Higher2004.Lower fuel costs in the first quarter of ~~2004,~~2005, compared with the same quarter of ~~2003,~~2004, resulted from ~~increased~~reduced nuclear generation. ~~Purchased~~Lower purchased power costs ~~were higher~~ in the first three months of ~~2004 reflecting a 4.8% increase 95~~ ~~in kilowatt-hour~~2005 reflected decreased KWH purchases and higher unit costs. ~~Lower nuclear~~Nuclear operating costs ~~occurred in large part~~increased due to the ~~absence in 2004 of a~~Perry scheduled refueling outage ~~at Beaver Valley Unit 1. Beaver Valley Unit 1 (65.00% ownership) experienced a refueling outage~~(including an unplanned extension) in the first quarter of ~~2003.~~ 2005 and the absence of nuclear refueling outages in the same period last year. Other operating expenses decreased primarily because of lower employee benefit costs.

Other Income (Expense)

Other income decreased $2 million in the first quarter of 2005, compared with the first quarter of 2004, due to the first quarter 2005 accruals for a potential $0.7 million civil penalty and $0.8 million for potential contributions toward environmentally beneficial projects related to the Sammis Plant settlement (see Outlook - Environmental Matters) and the absence of a 2004 $1 million gain from the sale of an investment.

Net Interest Charges

Net interest charges continued to trend lower, decreasing by ~~approximately $2 million~~$851,000 in the first quarter of ~~2004~~2005 from the same period last year, reflecting ~~mandatory and optional~~ redemptions of ~~$83~~$22 million total principal amount of debt securities since the first quarter of 2003. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, Penn recorded an after-tax credit to net income of $11 million. The cumulative adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was an $18 million increase to income, or $11 million net of income taxes. 2004.

Capital Resources and Liquidity ~~- ------------------------------- Penn's~~

Penn’s cash requirements in ~~2004 for~~2005and thereafterfor operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing Penn's net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next three years, Penn expects to meet its contractual obligations with cash from operations. Thereafter, Penn expects to usemetwith 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

Penn had ~~$40,000~~$38,000 of cash and cash equivalents as of March 31, ~~2004~~2005 and December 31, ~~2003.~~ 2004.

Cash Flows From Operating Activities ~~Cash~~

Net cash provided from operating activities ~~during~~in the first quarter of ~~2004,~~2005, compared with the corresponding 2004 period, ~~in 2003 were~~was as follows: ~~Operating~~

	Three Months Ended
	March 31,
Operating Cash Flows	2005		2004
	*(In millions)*

Cash earnings⁽¹⁾	$	30	$	38
Working capital and other		8		(3	)

Total Cash Flows from Operating Activities	$	38	$	35

⁽¹⁾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
	March 31,
Reconciliation of Cash Earnings	2005			2004
	*(In millions)*

Net Income (GAAP)	$	15		$	20
Non-Cash Charges (Credits):
Provision for depreciation		3			3
Amortization of regulatory assets		10			10
Nuclear fuel and other amortization		4			5
Deferred income taxes and investment tax credits, net		(2	)		(2	)
Other non-cash expenses		--			2
Cash earnings (Non-GAAP)	$	30		$	38

The $8 million decrease in cash earnings is described under“Results of Operations”. The $11 million working capital change was primarily due to changes of $12 million in receivables and $3 million in accrued taxes, partially offset by a $7 million change in accounts payable.

Cash Flows 2004 2003 ----------------------------------------------------------------- (In millions) Cash earnings (1).................. $38 $11 Working capital and other.......... -- 29 ----------------------------------------------------------------- Total.............................. $38 $40 ================================================================= (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. From Financing Activities

Net cash ~~from operating~~used for financing activities ~~decreased to $38~~totaled $10 million in the first quarter of ~~2004 from $40~~2005, compared with $22 million in the same period of 2003 due to a $27 million increase in cash earnings and a $29 million reduction from working capital and other changes (primarily change in accounts payable to associated companies). Cash Flows From Financing Activities In the first quarter of ~~2004, net cash used for financing activities increased to $22 million~~2004. This decrease resulted from ~~$14 million~~reduced debt redemptions in the ~~same period last year. The increase resulted from increased long-term debt redemptions, partially offset by increased short-term borrowings and reduced common stock dividends to OE.~~ first quarter of 2005, compared with the corresponding 2004 period.

Penn had ~~approximately $7 million~~$583,000 of cash and temporary investments (which ~~include~~included short-term notes receivable from associated companies) and ~~$40~~$11 million of short-term indebtedness with associated companies as of March 31, ~~2004.~~2005. Penn ~~may borrow~~has authorization from the SEC to incur short-term debt up to its ~~affiliates on a short-term basis.~~charter limit of $49 million (including the utility money pool). Penn had the capability to issue ~~$500~~$532 million of additional ~~first mortgage bonds~~FMB on the basis of property additions and retired ~~bonds.~~bonds as of March 31, 2005. Based upon applicable earnings coverage tests, Penn could issue up to ~~$521~~$367 million of preferred stock (assuming no additional debt was issued) as of March 31, ~~2004. In March 2004,~~ 2005.

Penn ~~completed an on-balance sheet, receivable financing transaction which allows it~~has the ability to borrow upfrom its regulated affiliates and FirstEnergy to ~~$25 million.~~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. Available bank borrowings include $1.75 billion from FirstEnergy’s and OE’s revolving credit facilities. 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 ~~borrowing~~ rate of interest is the same for each company receiving a loan from the pool and is based on ~~bank commercial paper rates.~~the average cost of funds available through the pool. The average interest rate for borrowings under these arrangements in the first quarter of 2005 was 2.66%.

In addition, Penn ~~is required to pay an annual~~has a $25 million receivables financing facility ~~fee of 0.40% on the entire finance limit. The facility was undrawn as~~through its subsidiary. As of March 31, ~~2004. This~~2005, the facility ~~matures on March 29, 2005. 96~~ ~~Penn's~~was undrawn; it expires June 30, 2005 and is expected to be renewed.

On May 16, 2005, Penn intends to redeem 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.

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 ~~of its~~ securities is stable. On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2 from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that the lower ratings were prompted by: "1) high consolidated leverage with significant holding company debt, 2) a degree of regulatory uncertainty in the service territories in which the company operates, 3) risks associated with investigations of the causes of the August 2003 blackout, and related securities litigation, and 4) a narrowing of the ratings range for the FirstEnergy operating utilities, given the degree to which FirstEnergy increasingly manages the utilities as a single system and the significant financial interrelationship among the subsidiaries."

Cash Flows From Investing Activities

Net cash used ~~for~~in investing activities totaled ~~$16~~$28 million in the first quarter of ~~2004,~~2005, compared ~~to $26~~with $13 million ~~for~~in the same quarter of 2004. The $15 million increase in the 2005 period ~~of 2003. The $10 million decrease~~reflects an increase in ~~funds used for investing activities resulted primarily from lower capital expenditures partially offset by changes in loans to associated companies.~~ property additions.

During the ~~last~~remaining three quarters of ~~2004,~~2005, capital requirements for property additions ~~and capital leases~~ are expected to be about ~~$70~~$67 million, including ~~$21~~$9 million for nuclear fuel. Penn has additional requirements of approximately ~~$22~~$2 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of ~~2004.~~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 $82 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to be approximately $64 million, of which about $13 million relates to 2005. During the same periods, Penn’s nuclear fuel investments are expected to be reduced by approximately $52 million and $17 million, respectively, as the nuclear fuel is consumed. Penn had no other material obligations as of March 31, 2005 that have not been recognized on its Consolidated Balance Sheet.

Equity Price Risk ~~- -----------------~~

Included in ~~Penn's~~Penn’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately ~~$51~~$56 million and ~~$50~~$57 million as of March 31, ~~2004~~2005 and December 31, ~~2003,~~2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $5$6 million reduction in fair value as of March 31, ~~2004.~~ 2005.

Outlook ~~- ------- Beginning in 1999,~~

The electric industry continues to transition to a more competitive environment and all of Penn's customers ~~were able to~~can select alternative energy suppliers. Penn continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. ~~The PPUC authorized Penn's rate restructuring plan, establishing~~Customer rates have been restructured into separate ~~charges for transmission, distribution, generation and stranded cost recovery, which is recovered through a CTC. Customers electing~~components to ~~obtain power from an alternative supplier have their bills reduced based on the regulated generation component, and the customers receive a generation charge from the alternative supplier.~~support customer choice. Penn has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain ~~limits, which is referred~~limits. Adopting new approaches to ~~as its PLR obligation.~~ regulation and experiencing new forms of competition have created new uncertainties.

Regulatory Matters ~~As part~~

Pennsylvania enacted its electric utility competition law in 1996 with the phase-in of customer choice for electric generation suppliers completed as of January 1, 2001. Penn's ~~transition plan it is obligated~~customer rates were restructured to ~~supply~~itemize (unbundle) the current price of electricity tointo its component elements - including generation, transmission, distribution and stranded cost recovery. In the event customers ~~who do not choose~~obtain power from an alternative ~~supplier. Penn's competitive retail sales affiliate, FES, acts as an alternate supplier for a~~source, the generation portion of the load in its franchise area. In late 2003, the PPUC issued a Tentative Order implementing new reliability benchmarks and standards. In connection therewith, the PPUC commenced a rulemaking procedure to amend the Electric Service Reliability Regulations to implement these new benchmarks, and create additional reporting on reliability. Although neither the Tentative Order nor the Reliability Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. The comment period for both the Tentative OrderPenn’s rates is excluded from their bill and the ~~Proposed Rulemaking Order has closed.~~customers receive a generation charge from the alternative supplier. The stranded cost recovery portion of rates provides for recovery of certain amounts not otherwise considered recoverable in a competitive generation market, including regulatory assets. Under the rate restructuring plan, Penn is ~~currently awaiting~~entitled to recover $236 million of stranded costs through the ~~PPUC to issue a final order~~CTC that began in ~~both matters. The order 97~~ ~~will determine (1) the standards~~1999 and ~~benchmarks to be utilized,~~ends in 2006.

Regulatory assets and (2) the details required in the quarterly and annual reports. On January 16, 2004, the PPUC initiated a formal investigation of whether Penn's "service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring" in Pennsylvania. Discovery has commenced in the proceeding and Penn's testimony is due May 14, 2004. Hearings are scheduled to begin August 3, 2004 in this investigation and the ALJ has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order by year end of 2004. Penn is unable to predict the outcome of the investigation or the impact of the PPUC order. Regulatory assetsliabilities 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. ~~All of~~ Penn's net regulatory ~~assets are expected to continue to be recovered under the provisions of its regulatory plan. Penn's regulatory assets totaled $15~~liabilities were approximately $27 million and ~~$28~~$18 million as of March 31, ~~2004~~2005 and December 31, ~~2003, respectively.~~ 2004, respectively, and are included in Noncurrent Liabilities on the Consolidated Balance Sheets.

See Note 13 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 ~~Various federal, state~~

Penn accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and ~~local authorities regulate Penn~~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 ~~regard~~reductions reaching 73% (from 2003 levels) by 2015, capping SO₂ emissions in affected states to ~~air and water quality and other environmental matters.~~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 ~~effects~~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.

Mercury Emissions

In December 2000, the EPA announced it would proceed with ~~regard~~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 ~~environmental matters could have~~reduce mercury emissions in two phases from coal-fired power plants. Initially, mercury emissions will decline by 2010 as a ~~material adverse effect on its earnings~~"co-benefit" from implementation of SO₂ and ~~competitive position. These environmental regulations affect Penn's earnings and competitive position to~~NO_x emission caps under the ~~extent that it competes with companies that are not subject to such regulations and therefore do not bear~~EPA's CAIR program. Phase II of the ~~risk~~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 ~~costs associated with compliance, or failure to comply, with such regulations. Overall, Penn believes it is in material~~ compliance with ~~existing~~these regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be. Penn is 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 $31,500 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. Penn cannot predict what action the EPA may ~~take in the future with respect to the interim enforcement policy.~~ be substantial.

W. H. Sammis Plant

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 ~~case, which deals with applicability~~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 ~~Prevention~~emissions to economic output - by 18 percent through 2012.

Penn cannot currently estimate the financial impact of ~~Significant Deterioration provisions~~climate change policies, although the potential restrictions on CO₂ emissions could require significant capital and other expenditures. However, the CO₂ emissions per KWH of the Clean Air Act. The remedy phase, which is currently scheduled to be ready for trial beginning July 19, 2004, will address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant. In the ruling, the Court indicated that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact on Penn's financial condition and results of operations. Management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of March 31, 2004.electricity generated by Penn is ~~complying with SO2 reduction requirements under~~lower than many regional competitors due to Penn's diversified generation sources which include low or non-CO₂ emitting gas-fired and nuclear generators.

FirstEnergy plans to issue a report that will disclose the ~~Clean Air Act Amendments of 1990~~Companies’ environmental activities, including their plans to respond to environmental requirements. FirstEnergy expects to complete the report by ~~burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions required by~~December 1, 2005 and will post the ~~1990 Amendments~~report on its web site,www.firstenergycorp.com.

Other Legal Proceedings

There are ~~being achieved through combustion controls~~various lawsuits, claims (including claims for asbestos exposure) and ~~the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from~~proceedings related to Penn's ~~Ohio and Pennsylvania facilities.~~normal business operations pending against Penn. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOx emissionsmost significant not otherwise discussed above are contributing significantly to ozone levels in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets. Pennsylvania submitted a SIP that required compliance with the NOx budgets at Penn's Pennsylvania facilities by May 1, 2003. Ohio submitted a SIP that requires compliance with the NOx budgets at Penn's Ohio facilities by May 31, 2004. Penn's facilities have complied with the NOx budgets in 2003 and 2004, respectively. 98 ~~Power Outage~~ described below.

On August 14, 2003, various states and parts of southern Canada experienced a widespread power ~~outage. That outage~~outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. ~~On April 5, 2004, the~~The U.S. - ~~-Canada~~Canada Power System Outage Task ~~Force released its~~Force’s final report in April 2004 on ~~this outage. The final report supercedes~~ the ~~interim report that had been issued in November, 2003. In the final report, the Task Force~~outages concluded, among other things, that the problems leading to the ~~outage~~outages began in ~~FirstEnergy's~~FirstEnergy’s Ohio service ~~area. Specifically,~~area.Specifically, the final report concludes, among other things, that the initiation of the August ~~14th~~14, 2003 power ~~outage~~outages resulted from ~~the coincidence on that afternoon of several events, including,~~ 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~~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~~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 ~~14th~~14, 2003 power ~~outage~~outages and that it does not adequately address the underlying causes of the ~~outage.~~outages. FirstEnergy remains convinced that the ~~outage~~outages cannot be explained by events on any one utility's system. The final report ~~contains~~contained 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations ~~relate~~related to broad industry or policy matters while one, ~~relates~~including subparts, related to activities the Task Force ~~recommends~~recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and ~~ECAR.~~other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy ~~has undertaken~~implemented several initiatives, ~~some~~both prior to and ~~some~~ since the August ~~14th~~14, 2003 power ~~outage, to enhance reliability~~outages, which ~~are~~were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and ~~believes it will complete those relating to summer 2004 by June 30 (see Reliability Initiatives below).~~collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these initiatives already were in process, ~~and budgeted in 2004,~~ FirstEnergy does not believe that any incremental expenses associated with additional initiatives ~~undertaken during~~completed in 2004 ~~will have~~had a material effect on its continuing operations or financial results. FirstEnergy notes, however, that the 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. ~~Reliability Initiatives On October 15, 2003, NERC issued~~FirstEnergy has not accrued a ~~Near Term Action Plan~~liability as of March 31, 2005 for any expenditures in excess of those actually incurred through that ~~contained recommendations for all control areas and reliability coordinators with respect to enhancing system reliability. Approximately 20~~date.

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 ~~recommendations~~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 ~~directed~~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.

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 past two years. FENOC operates the Perry Nuclear Power Plant, in which Penn has a 5.24% interest. On April 4, 2005, the NRC held a public forum to discuss FENOC’s performance at the ~~FirstEnergy companies~~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 ~~broadly focused on initiatives~~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 ~~are recommended for completion by summer 2004. These initiatives principally relate to changes in voltage criteria~~additional inspections will continue and reactive resources management; operational preparedness and action plans; emergency response capabilities; and, preparedness and operating center training. FirstEnergy presented a detailed compliance plan to NERC, which NERC subsequently endorsed on May 7, 2004, andthat the ~~various initiatives are expected~~plant must improve performance to be completed no later than June 30, 2004. On February 26-27, 2004, certain FirstEnergy companies participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC to review control area operations throughout muchremoved from the Multiple/Repetitive Degraded Cornerstone Column of the ~~United States during 2004, is~~Action Matrix. 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 12(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

FIN 47,“Accounting for Conditional Asset Retirement Obligations - an independent review to identify areas for improvement. The final audit report was completed on April 30, 2004. The report identified positive observations and included various recommendations for improvement. FirstEnergy is currently reviewing the audit results and recommendations and expects to implement those relating to summer 2004 by June 30. Based on its review thus far, FirstEnergy believes that noneinterpretation of the recommendations identify a need for any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that NERC 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. FASB Statement No. 143”

On March ~~1, 2004, certain FirstEnergy~~30, 2005, the FASB issued this interpretation to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies ~~filed, in accordance with~~are required to recognize a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. - Canada Power System Outage Task Force interim report. In particular, the filing addressed upgrades to FirstEnergy's control room computer hardware and software and enhancements to the training of control room operators. The PUCO will review the plan before determining the next steps, if any, in the proceeding. On April 22, 2004, FirstEnergy filed with FERC the results of the FERC-ordered independent study of part of Ohio's power grid. The study examined, among other things, the reliability of the transmission grid in critical points in the Northern Ohio area and the need, if any, for reactive power reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing the results of that study and expects to complete the implementation of recommendations relating to 2004 by this summer. Based on its review thus far, FirstEnergy believes that the study does not recommend any incremental material investment or upgrades to existing equipment. 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. 99 With respect to each of the foregoing initiatives, FirstEnergy has requested and NERC has agreed to provide, a technical assistance team of experts to provide ongoing guidance and assistance in implementing and confirming timely and successful completion. Legal Matters Various lawsuits, claims and proceedings related to Penn's normal business operations are pending against Penn, the most significant of which are described above. Critical Accounting Policies Penn prepares its financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of Penn's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Penn's more significant accounting policies are described below. Regulatory Accounting Penn is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine Penn is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. Penn regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Revenue Recognition Penn follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, consumption by customer class and electricity provided from alternative suppliers. Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87 and SFAS 106, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to recent declines in corporate bond yields and interest rates in general, FirstEnergy reduced the assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. 100 ~~FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts~~liability for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first quarter of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Long-Lived Assets In accordance with SFAS 144, Penn periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carryingfair value of an asset ~~might not be fully recoverable. The accounting standard requires~~retirement obligation that ~~if the sum of~~is conditional on a future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, Penn recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). The calculation of future cash flows is based on assumptions, estimates and judgement about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. Nuclear Decommissioning In accordance with SFAS 143, Penn recognizes an ARO for the future decommissioning of its nuclear power plants. The ARO liability represents an estimate of the fair value of Penn's current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. Penn used an expected cash flow approach (as discussed in FASB Concepts Statement No. 7) to measureevent, if the fair value of the ~~nuclear decommissioning ARO.~~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 ~~approach applies probability weighting~~interpretation is effective no later than the end of fiscal years ending after December 15, 2005. FirstEnergy is currently evaluating the effect this standard will have on the financial statements.

EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to ~~discounted future cash flow scenarios that reflect~~Certain Investments"

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,

	2005			2004

STATEMENTS OF INCOME	*(In thousands)*

OPERATING REVENUES	$	529,092		$	498,124

OPERATING EXPENSES AND TAXES:
Purchased power		277,132			270,733
Other operating costs		101,067			86,816
Provision for depreciation		20,206			19,075
Amortization of regulatory assets		68,374			64,485
General taxes		15,440			15,932
Income taxes		12,483			9,113
Total operating expenses and taxes		494,702			466,154

OPERATING INCOME		34,390			31,970

OTHER INCOME (net of income taxes)		44			1,503

NET INTEREST CHARGES:
Interest on long-term debt		19,405			20,728
Allowance for borrowed funds used during construction		(403	)		(120	)
Deferred interest		(911	)		(923	)
Other interest expense		1,824			390
Net interest charges		19,915			20,075

NET INCOME		14,519			13,398

PREFERRED STOCK DIVIDEND REQUIREMENTS		125			125

EARNINGS ON COMMON STOCK	$	14,394		$	13,273

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	14,519		$	13,398

OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gain (loss) on derivative hedges		69			(14	)
Unrealized loss on available for sale securities		--			(8	)
Other comprehensive income (loss)		69			(22	)
Income tax related to other comprehensive income		(28	)		3
Other comprehensive income (loss), net of tax		41			(19	)

TOTAL COMPREHENSIVE INCOME	$	14,560		$	13,379

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

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2005			2004
	*(In thousands)*
ASSETS
UTILITY PLANT:
In service	$	3,755,666		$	3,730,767
Less - Accumulated provision for depreciation		1,395,942			1,380,775
		2,359,724			2,349,992
Construction work in progress		76,054			75,012
		2,435,778			2,425,004
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		137,142			138,205
Nuclear fuel disposal trust		160,757			159,696
Long-term notes receivable from associated companies		21,335			20,436
Other		16,362			19,379
		335,596			337,716
CURRENT ASSETS:
Cash and cash equivalents		41			162
Receivables-
Customers (less accumulated provisions of $3,090,000 and $3,881,000,
respectively, for uncollectible accounts)		201,196			201,415
Associated companies		34,961			86,531
Other (less accumulated provisions of $263,000 and $162,000,
respectively, for uncollectible accounts)		76,837			39,898
Materials and supplies, at average cost		2,352			2,435
Prepayments and other		22,239			31,489
		337,626			361,930
DEFERRED CHARGES:
Regulatory assets		2,267,795			2,176,520
Goodwill		1,983,740			1,985,036
Other		4,568			4,978
		4,256,103			4,166,534
	$	7,365,103		$	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		3,013,912			3,013,912
Accumulated other comprehensive loss		(55,493	)		(55,534	)
Retained earnings		37,665			43,271
Total common stockholder's equity		3,149,797			3,155,362
Preferred stock		12,649			12,649
Long-term debt and other long-term obligations		1,229,210			1,238,984
		4,391,656			4,406,995
CURRENT LIABILITIES:
Currently payable long-term debt		22,381			16,866
Notes payable-
Associated companies		204,794			248,532
Accounts payable-
Associated companies		9,248			20,605
Other		105,699			124,733
Accrued taxes		41,503			2,626
Accrued interest		25,078			10,359
Other		68,192			65,130
		476,895			488,851
NONCURRENT LIABILITIES:
Power purchase contract loss liability		1,325,786			1,268,478
Accumulated deferred income taxes		688,248			645,741
Nuclear fuel disposal costs		171,014			169,884
Asset retirement obligation		73,754			72,655
Retirement benefits		98,307			103,036
Other		139,443			135,544
		2,496,552			2,395,338
COMMITMENTS AND CONTINGENCIES (Note 12)
	$	7,365,103		$	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.

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31,

	2005			2004

	*(In thousands)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	14,519		$	13,398
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		20,206			19,075
Amortization of regulatory assets		68,374			64,485
Deferred costs, net		(73,359	)		(37,981	)
Deferred income taxes and investment tax credits, net		7,169			230
Accrued retirement benefit obligation		(4,728	)		(11,714	)
Accrued compensation, net		5,413			(855	)
Decrease (Increase) in operating assets:
Receivables		14,849			1,438
Materials and supplies		82			358
Prepayments and other current assets		9,250			24,376
Increase (Decrease) in operating liabilities:
Accounts payable		(30,390	)		(15,349	)
Accrued taxes		38,877			49,480
Accrued interest		14,719			10,778
Other		12,321			4,323
Net cash provided from operating activities		97,302			122,042

CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Long-term debt		(3,883	)		(3,591	)
Short-term borrowings, net		(43,738	)		(79,744	)
Dividend Payments-
Common stock		(20,000	)		(5,000	)
Preferred stock		(125	)		(125	)
Net cash used for financing activities		(67,746	)		(88,460	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(28,124	)		(28,212	)
Loans to associated companies, net		(898	)		(1,056	)
Other		(655	)		(4,303	)
Net cash used for investing activities		(29,677	)		(33,571	)

Net increase (decrease) in cash and cash equivalents		(121	)		11
Cash and cash equivalents at beginning of period		162			271
Cash and cash equivalents at end of period	$	41		$	282


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

Report of the Medicare Act. Penn elected to defer the effects of the Medicare Act due to the lack of specific guidance. Pursuant to FSP 106-1, Penn began accounting for the effects of the Medicare Act effective January 1, 2004 as a result of a February 2, 2004 plan amendment that required remeasurement of the plan's obligations. See Note 2 for a discussion of the effect of the federal subsidy and plan amendment on the consolidated financial statements. 101 ~~JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited)~~
Three Months Ended March 31, ------------------------- 2004 2003 --------- -------- Restated (See Note 2) (In thousands) OPERATING REVENUES.............................................................. $ 498,124 $ 656,952 --------- --------- OPERATING EXPENSES AND TAXES: Fuel......................................................................... 1,213 1,334 Purchased power.............................................................. 259,592 362,667 Other operating costs........................................................ 85,603 69,088 --------- --------- Total operation and maintenance expenses................................. 346,408 433,089 Provision for depreciation and amortization.................................. 94,701 96,973 General taxes................................................................ 15,932 15,812 Income taxes................................................................. 9,113 35,735 --------- --------- Total operating expenses and taxes....................................... 466,154 581,609 --------- --------- OPERATING INCOME................................................................ 31,970 75,343 OTHER INCOME.................................................................... 1,503 1,176 --------- --------- INCOME BEFORE NET INTEREST CHARGES.............................................. 33,473 76,519 --------- --------- NET INTEREST CHARGES: Interest on long-term debt................................................... 20,728 23,312 Allowance for borrowed funds used during construction........................ (120) (123) Deferred interest............................................................ (923) (3,202) Other interest expense (credit).............................................. 390 (159) Subsidiary's preferred stock dividend requirements........................... -- 2,674 --------- --------- Net interest charges..................................................... 20,075 22,502 --------- --------- NET INCOME...................................................................... 13,398 54,017 PREFERRED STOCK DIVIDEND REQUIREMENTS........................................... 125 125 --------- --------- EARNINGS ON COMMON STOCK........................................................ $ 13,273 $ 53,892 ========= ========= ~~The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these statements.~~ ~~102~~
~~JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)~~
March 31, December 31, 2004 2003 ----------------------------- (In thousands) ASSETS UTILITY PLANT: In service..................................................................... $3,660,955 $3,642,467 Less-Accumulated provision for depreciation.................................... 1,383,599 1,367,042 ---------- ---------- 2,277,356 2,275,425 Construction work in progress.................................................. 56,735 48,985 ---------- ---------- 2,334,091 2,324,410 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Nuclear plant decommissioning trusts........................................... 130,623 125,945 Nuclear fuel disposal trust.................................................... 159,710 155,774 Long-term notes receivable from associated companies........................... 20,635 19,579 Other.......................................................................... 18,085 18,744 ---------- ---------- 329,053 320,042 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents...................................................... 282 271 Receivables- Customers (less accumulated provisions of $3,924,000 and $4,296,000 respectively, for uncollectible accounts).................................. 182,797 198,061 Associated companies......................................................... 95,370 70,012 Other (less accumulated provisions of $836,000 and $1,183,000 respectively, for uncollectible accounts).................................. 34,879 46,411 Materials and supplies, at average cost........................................ 2,122 2,480 Prepayments and other.......................................................... 24,984 49,360 ---------- ---------- 340,434 366,595 ---------- ---------- DEFERRED CHARGES: Regulatory assets.............................................................. 2,456,605 2,558,214 Goodwill....................................................................... 1,998,287 2,001,302 Other.......................................................................... 8,547 8,481 ---------- ---------- 4,463,439 4,567,997 ---------- ---------- $7,467,017 $7,579,044 ========== ========== 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........................................................ 3,029,894 3,029,894 Accumulated other comprehensive loss......................................... (51,784) (51,765) Retained earnings............................................................ 30,406 22,132 ---------- ---------- Total common stockholder's equity........................................ 3,162,229 3,153,974 Preferred stock not subject to mandatory redemption............................ 12,649 12,649 Long-term debt................................................................. 1,041,032 1,095,991 ---------- ---------- 4,215,910 4,262,614 --------- ---------- CURRENT LIABILITIES: Currently payable long-term debt............................................... 226,313 175,921 Notes payable - Associated companies......................................................... 151,241 230,985 Accounts payable- Associated companies......................................................... 42,066 42,410 Other........................................................................ 90,810 105,815 Accrued taxes................................................................. 50,400 919 Accrued interest............................................................... 25,621 14,843 Other.......................................................................... 60,140 58,094 ---------- ---------- 646,591 628,987 ---------- ---------- NONCURRENT LIABILITIES: Accumulated deferred income taxes.............................................. 623,875 640,208 Accumulated deferred investment tax credits.................................... 7,315 7,711 Power purchase contract loss liability ........................................ 1,416,257 1,473,070 Nuclear fuel disposal costs.................................................... 168,314 167,936 Asset retirement obligation.................................................... 111,379 109,851 Retirement benefits............................................................ 147,505 159,219 Other.......................................................................... 129,871 129,448 --------- ---------- 2,604,516 2,687,443 COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................ ---------- ---------- ---------- ---------- $7,467,017 $7,579,044 ========== ========== ~~The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these balance sheets.~~ ~~103~~
~~JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)~~
Three Months Ended March 31, --------------------------- 2004 2003 --------- -------- Restated (See Note 2) (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................................... $ 13,398 $ 54,017 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........................... 94,701 96,973 Other amortization.................................................... 24 185 Deferred costs, net................................................... (49,122) (71,888) Deferred income taxes, net............................................ 627 14,977 Investment tax credits, net........................................... (397) (575) Receivables........................................................... 1,438 19,788 Materials and supplies................................................ 358 (226) Accounts payable...................................................... (15,349) (90,178) Prepayments and other current assets.................................. 24,376 16,044 Accrued taxes......................................................... 49,480 45,157 Accrued interest...................................................... 10,778 5,771 Accrued retirement benefit obligation................................. (11,714) -- Other................................................................. 3,444 6,034 --------- --------- Net cash provided from operating activities......................... 122,042 96,079 --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Redemptions and Repayments - Long-term debt.......................................................... (3,591) (10,090) Short-term borrowings, net.............................................. (79,744) -- Dividend Payments- Common stock............................................................ (5,000) (89,000) Preferred stock......................................................... (125) (125) --------- --------- Net cash used for financing activities.............................. (88,460) (99,215) --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................ (28,212) (24,551) Loans from (to) associated companies, net................................. (1,056) 24,750 Other..................................................................... (4,303) (50) --------- --------- Net cash provided from (used for) investing activities.............. (33,571) 149 --------- --------- Net increase (decrease) in cash and cash equivalents......................... 11 (2,987) Cash and cash equivalents at beginning of period ............................ 271 4,823 --------- --------- Cash and cash equivalents at end of period................................... $ 282 $ 1,836 ========= ========= ~~The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these statements.~~ ~~104~~
~~REPORT OF INDEPENDENT ACCOUNTANTS~~ 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 March 31, ~~2004,~~2005, and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, ~~2004~~2005 and ~~2003.~~2004. These interim financial statements are the responsibility of the ~~Company's~~Company’s management.

We previously audited, in accordance with ~~auditing~~the standards ~~generally accepted in~~of the ~~United States of America,~~Public Company Accounting Oversight Board (United States), the consolidated balance sheet ~~and the consolidated statement of capitalization~~ as of December 31, ~~2003,~~2004, and the related consolidated statements of income, capitalization, common ~~stockholder's~~stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, ~~(not presented herein),~~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~~Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note ~~1(E)~~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 ~~February 25, 2004,~~March 7, 2005, we expressed an unqualified ~~opinion on those~~opinions thereon. The consolidated financial ~~statements.~~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 ~~condensed~~ consolidated balance sheet information as of December 31, ~~2003,~~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

May ~~7, 2004 105~~ 3, 2005

JERSEY CENTRAL POWER & LIGHT COMPANY ~~MANAGEMENT'S~~

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 ~~provides~~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 in ~~northern, western~~unbundled service charges and ~~east central New Jersey. New Jersey~~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 first quarter of 2005 increased to $14 million from $13 million in 2004, principally due to higher operating revenues, partially offset by increases in other operating, purchased power costs and regulatory asset amortization.

Operating revenues increased $31 million or 6.2% in the first quarter of 2005 compared with 2004. The higher revenues primarily resulted from increases in retail electric generation sales of $18 million and distribution revenues of $12 million partially offset by a $4 million decline in wholesale revenues.

The higher revenues from generation sales to residential and commercial customers ~~are able~~(residential - $14 million and commercial - $9 million) were due to ~~choose their electricity~~increases in sales volume (residential - 13.2% and commercial - 9.2%) and higher unit prices discussed below. The sales volume increase was primarily due to lower customer shopping. Generation provided by alternative suppliers as a percent of total sales delivered in JCP&L’s service area decreased by 12.1 and 3.7 percentage points for residential and commercial customers, respectively. A $5 million decrease in industrial sales reflected the effect of increased customer shopping which resulted in a 33.3% KWH sales decrease.

JCP&L's BGS obligation has been transferred to external parties as a result of ~~legislation~~an NJBPU auction process that extended the termination of JCP&L's BGS obligation through May 2005 (see Outlook - Regulatory Matters). The higher unit prices resulted from the BGS auction. The increased total retail generation KWH sales reduced energy available for sale in the wholesale market which resulted in lower wholesale sales revenues of $4 million (15.4% KWH sales decrease).

The increase in distribution revenues in all customer sectors of $12 million in the first quarter of 2005 compared to the first quarter of 2004 was primarily due to higher composite unit prices. The 3.9% commercial sector KWH sales increase was offset by minor declines in both the residential and industrial sectors.

The higher operating revenues also reflected a $2 million payment received in the first quarter 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. This payment is credited to JCP&L’s customers, resulting in no net earnings effect.

Changes in kilowatt-hour sales by customer class in the first quarter of 2005 compared to the first quarter of 2004 are summarized in the following table:


Changes in Kilowatt-hour Sales	2005

*Increase (Decrease*)
Electric Generation:
Retail		8.4	%
Wholesale		(15.4	)%
Total Electric Generation Sales		2.3	%

Distribution Deliveries:
Residential		(0.5	)%
Commercial		3.9	%
Industrial		(0.1	)%
Total Distribution Deliveries		1.4	%

Operating Expenses and Taxes

Total operating expenses and taxes increased $29 million in the first quarter of 2005 compared to the prior year. Purchased power costs increased $6 million in the first quarter of 2005 compared to 2004. The higher purchased power costs reflected higher KWH purchased due to increased retail generation sales. The increase of $14 million in other operating costs in the first quarter of 2005 compared to 2004 reflected 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.

Amortization of regulatory assets increased $4 million in the first quarter of 2005. The higher amortization was caused by 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 March 31, 2005, JCP&L had $41,000 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.

Cash Flows From Operating Activities

Cash provided from operating activities in the first quarter of 2005 compared with the first quarter of 2004, were as follows:

Operating Cash Flows	2005		2004
	*(In millions)*

Cash earnings⁽¹⁾	$	37	$	47
Working capital and other		60		75
Total Cash Flows from Operating Activities	$	97	$	122

⁽¹⁾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.

Reconciliation of Cash Earnings	2005			2004
	*(In millions)*

Net Income (GAAP)	$	15		$	13
Non-Cash Charges (Credits):
Provision for depreciation		20			19
Amortization of regulatory assets		68			64
Deferred costs recoverable as regulatory assets		(73	)		(38	)
Deferred income taxes		7			--
Other non-cash expenses		--			(11	)
Cash earnings (Non-GAAP)	$	37		$	47

The $10 million decrease in cash earnings is described above and under "Results of Operations". The $15 million decrease from working capital primarily resulted from changes in prepayments and accounts payable of approximately $15 million each, partially offset by a $13 million change in receivables.

100

Cash Flows From Financing Activities

Net cash used for financing activities decreased to $68 million in the first quarter of 2005 from $88 million in same period of 2004. The decrease resulted from a $36 million decrease in net debt redemptions partially offset by a $15 million increase in common stock dividends to FirstEnergy.

JCP&L had about $41,000 of cash and temporary investments and approximately $205 million of short-term indebtedness as of March 31, 2005. JCP&L has authorization from the SEC to incur short-term debt up to its charter limit of $1.038 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 March 31, 2005, JCP&L had the capability to issue $578 million of additional senior notes based upon FMB collateral. As of March 31, 2005, based upon applicable earnings coverage tests and its charter, JCP&L could issue $564 million of preferred stock (assuming no additional debt was issued).

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 in the first quarter of 2005 was 2.66%.

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 stable.

Cash Flows From Investing Activities

Net cash used in investing activities was $30 million in the first quarter of 2005 compared to $34 million in the previous year. The $4 million decrease primarily resulted from a $4 million decrease in property removal costs.

During the last three quarters of 2005, capital requirements for property additions and improvements are expected to be about $150 million.

JCP&L’s capital spending for the period 2005-2007 is expected to be about $511 million for property additions, of which approximately $178 million applies to 2005.

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. They are responsible for promoting the effective design and implementation of sound risk management programs. They also oversee compliance with corporate risk management policies and established risk management practices.

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 March 31, 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 as a decrease in a regulatory liability and, therefore, had no impact on net income.

101

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, we rely 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. The valuation of the derivative contract at March 31, 2005 uses prices from sources shown in the following table:

Source of Information - Fair Value by Contract Year

	2005		2006		2007		2008		Thereafter		Total
	*(In millions)*

Other external sources⁽¹⁾	$	3	$	3	$	--	$	--	$	--	$	6
Prices based on models		--		--		2		2		4		8

Total⁽²⁾	$	3	$	3	$	2	$	2	$	4	$	14

⁽¹⁾Broker quote sheets.

⁽²⁾Includes $14 million from an embedded option that is offset by a regulatory liability and does not affect earnings.

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 March 31, 2005.

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $78 million and $80 million at March 31, 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 March 31, 2005.

Outlook

The electric industry continues to transition to a more competitive environment and all ot JCP&L's customers can select alternative energy suppliers. JCP&L 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. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties.

Regulatory Matters

Beginning in 1999, all of JCP&L's customers had a choice for electric generation suppliers. JCP&L's customer rates were restructured into unbundled service charges and additional non-bypassable charges to recover stranded costs.

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 March 31, 2005 and December 31, 2004 were $2.3 billion and $2.2 billion, respectively.

The July 2003 NJBPU decision on JCP&L's base electric rate proceeding ordered a Phase II proceeding be conducted to review whether JCP&L is in compliance with current service reliability and quality standards. The NJBPU also ordered that any expenditures and projects undertaken by JCP&L to increase its system's reliability be reviewed as part of the Phase II proceeding, to determine their prudence and reasonableness for rate recovery. In that Phase II proceeding, the NJBPU could increase JCP&L’s return on equity to 9.75% or decrease it to 9.25%, depending on its assessment of the reliability of JCP&L's service. Any reduction would be retroactive to August 1, 2003. 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 requests an increase to the MTC deferred balance recovery of approximately $20 million annually. The Ratepayer Advocate filed testimony on November 16, 2004, and JCP&L submitted rebuttal testimony on January 4, 2005. The Ratepayer Advocate surrebuttal testimony was submitted February 8, 2005. Discovery and settlement conferences are ongoing.

102

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.

See Note 13 to the consolidated financial statements for further details and a complete discussion of regulatory matters in New Jersey.

Employee Matters

On March 15, 2005, members of the International Brotherhood of Electrical Workers System Council U-3 ratified a new four-year contract with JCP&L. Ratification of the contract resolved issues surrounding health care and work rules, and ended a 14-week strike against JCP&L by the Council’s members.

Environmental Matters

JCP&L 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 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 March 31, 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 March 31, 2005.

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.

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.

103

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 Court 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 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 Court. 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 March 31, 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 included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these initiatives already were in process, FirstEnergy does not believe that any incremental expenses associated with additional initiatives completed in 2004 had a material effect on its continuing operations or financial results. FirstEnergy notes, however, that the 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. FirstEnergy has not accrued a liability as of March 31, 2005 for any expenditures in excess of those actually incurred through that date.

New Accounting Standards and Interpretations

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

104

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

105

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,

	2005			2004

	*(In thousands)*

OPERATING REVENUES	$	295,781		$	260,898

OPERATING EXPENSES AND TAXES:
Fuel and purchased power		150,133			143,456
Other operating costs		58,430			33,048
Provision for depreciation		11,521			9,898
Amortization of regulatory assets		28,621			25,497
General taxes		19,272			17,736
Income taxes		6,732			7,980
Total operating expenses and taxes		274,709			237,615

OPERATING INCOME		21,072			23,283

OTHER INCOME (net of income taxes)		6,449			5,526

NET INTEREST CHARGES:
Interest on long-term debt		9,560			10,147
Allowance for borrowed funds used during construction		(178	)		(71	)
Other interest expense		1,663			689
Net interest charges		11,045			10,765

NET INCOME	$	16,476		$	18,044

OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gain (loss) on derivative hedges		84			(3,260	)
Unrealized gain on available for sale securities		--			22
Other comprehensive income (loss)		84			(3,238	)
Income tax related to other comprehensive income		(35	)		(9	)
Other comprehensive income (loss), net of tax		49			(3,247	)

TOTAL COMPREHENSIVE INCOME	$	16,525		$	14,797


The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral partof these statements.

106

METROPOLITAN EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)

	March 31,			December 31,
	2005			2004
	*(In thousands)*
ASSETS
UTILITY PLANT:
In service	$	1,796,340		$	1,800,569
Less - Accumulated provision for depreciation		697,927			709,895
		1,098,413			1,090,674
Construction work in progress		19,714			21,735
		1,118,127			1,112,409
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		216,061			216,951
Long-term notes receivable from associated companies		10,775			10,453
Other		28,899			34,767
		255,735			262,171
CURRENT ASSETS:
Cash and cash equivalents		120			120
Notes receivable from associated companies		21,570			18,769
Receivables-
Customers (less accumulated provisions of $4,418,000 and $4,578,000,
respectively, for uncollectible accounts)		126,303			119,858
Associated companies		42,649			118,245
Other (less accumulated provision of $29,000 for uncollectible accounts in 2005)		14,932			15,493
Prepayments and other		45,192			11,057
		250,766			283,542
DEFERRED CHARGES:
Goodwill		867,769			869,585
Regulatory assets		750,244			693,133
Other		24,140			24,438
		1,642,153			1,587,156
	$	3,266,781		$	3,245,278
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 900,000 shares -
859,500 shares outstanding	$	1,289,943		$	1,289,943
Accumulated other comprehensive loss		(43,441	)		(43,490	)
Retained earnings		46,442			38,966
Total common stockholder's equity		1,292,944			1,285,419
Long-term debt and other long-term obligations		694,214			701,736
		1,987,158			1,987,155
CURRENT LIABILITIES:
Currently payable long-term debt		37,395			30,435
Short-term borrowings-
Associated companies		108,677			80,090
Accounts payable-
Associated companies		30,959			88,879
Other		34,426			26,097
Accrued taxes		2,286			11,957
Accrued interest		10,445			11,618
Other		17,741			23,076
		241,929			272,152
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		314,193			305,389
Accumulated deferred investment tax credits		10,662			10,868
Power purchase contract loss liability		393,825			349,980
Nuclear fuel disposal costs		38,631			38,408
Asset retirement obligation		134,964			132,887
Retirement benefits		80,571			82,218
Other		64,848			66,221
		1,037,694			985,971
COMMITMENTS AND CONTINGENCIES (Note 12)
	$	3,266,781		$	3,245,278

The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of thesebalance sheets.

107

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31,

	2005			2004

	*(In thousands)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	16,476		$	18,044
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		11,521			9,898
Amortization of regulatory assets		28,621			25,497
Deferred costs recoverable as regulatory assets		(16,441	)		(16,792	)
Deferred income taxes and investment tax credits, net		(11	)		2,433
Accrued retirement benefit obligation		(1,647	)		1,074
Accrued compensation, net		(1,723	)		(634	)
Decrease (Increase) in operating assets:
Receivables		69,712			5,767
Materials and supplies		(18	)		18
Prepayments and other current assets		(34,117	)		(36,618	)
Increase (Decrease) in operating liabilities:
Accounts payable		(49,591	)		6,848
Accrued taxes		(9,671	)		(1,546	)
Accrued interest		(1,173	)		(4,465	)
Other		(9,134	)		(8,265	)
Net cash provided from operating activities		2,804			1,259

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		--			247,607
Short-term borrowings, net		28,587			--
Redemptions and Repayments-
Long-term debt		(435	)		(50,435	)
Short-term borrowings, net		--			(65,335	)
Dividend Payments-
Common stock		(9,000	)		(5,000	)
Net cash provided from financing activities		19,152			126,837

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(16,199	)		(8,962	)
Contributions to nuclear decommissioning trusts		(2,371	)		(2,371	)
Loans to associated companies, net		(3,150	)		(116,802	)
Other		(236	)		38
Net cash used for investing activities		(21,956	)		(128,097	)

Net increase (decrease) in cash and cash equivalents		--			(1	)
Cash and cash equivalents at beginning of period		120			121
Cash and cash equivalents at end of period	$	120		$	120

The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are anintegral part of these statements.

108

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 March 31, 2005, and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 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.

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

May 3, 2005

109

METROPOLITAN EDISON COMPANY

MANAGEMENT’S DISCUSSION AND

ANALYSIS OF RESULTS OF OPERATIONS

AND FINANCIAL CONDITION

Met-Ed is a wholly owned, electric utility ~~industry. JCP&L's regulatory plan required unbundling~~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. ~~Also under the regulatory plan, JCP&L~~Met-Ed continues to deliver power to homes and businesses through its existing distribution ~~system and is required to maintain the PLR obligation known as BGS for customers who elect to retain JCP&L as their power supplier. Restatements~~system.

Results of Previously Reported Quarterly Results - ----------------------------------------------------- As discussed in Note 2 to Consolidated Financial Statements, JCP&L's quarterly results for the first quarter of 2003 have been restated to correct the amounts reported for operating expenses. JCP&L's costs which were originally recorded as operating expenses and should have been capitalized to construction were $0.2 million ($0.1 million after-tax)Operations

Net income in the first quarter of 2003. The impact of these adjustments was not material to JCP&L's Consolidated Balance Sheets or Consolidated Statements of Cash Flows for any quarter of 2003. Results of Operation - -------------------- Earnings on common stock in the first quarter of 20042005 decreased to ~~$13~~$16 million from $54 million in the first quarter of 2003. Lower operating revenues primarily due to decreases in wholesale sales and lower rates resulting from a NJBPU rate order and higher operating costs were partially offset by lower purchased power costs. Operating revenues decreased by $159 million or 24.2% in the first quarter of 2004 compared with the same period in 2003. The lower revenues resulted from lower wholesale revenues that decreased by $78 million over the first quarter of 2003. JCP&L entered into long-term power purchase agreements with the divestiture of its generating facilities. JCP&L was able to sell any power in excess of its retail customer needs to the wholesale market. The long-term power purchase agreements ended during 2003 and as a result, sales to the wholesale market also ceased. While distribution deliveries increased 1.3% in the first quarter of 2004 from the corresponding quarter of 2003, revenues from electricity throughput declined by $76 million. On July 25, 2003, the NJBPU announced its JCP&L base electric rate proceeding decision (see Regulatory Matters), which reduced JCP&L's distribution rates effective August 1, 2003. The lower rates reduced revenues by $33$18 million in the first quarter of 2004. AThe decrease was due to increases in purchased power costs, amortization of regulatory assets, other operating costs and general taxes. The decrease was partially offset by increased operating revenues.

Operating revenues increased by $35 million, or 13.4% in the first quarter of 2005 compared with the first quarter of 2004. The higher ~~level~~revenues primarily resulted from increases of retail generation electric sales of $15 million and distribution revenues of $6 million. The higher generation sales revenues in all customer sectors reflected the effect of a 10.1% KWH sales increase and higher composite unit prices. The sales volume increase resulted from lower customer shopping ~~contributed~~due to customers returning to Met-Ed as their generation supplier. Sales by alternative suppliers as a percent of total sales delivered in Met-Ed’s franchise area decreased by 18.2, 1.4 and 0.1 percentage points in the industrial, commercial and residential sectors, respectively.

Revenues from distribution throughput increased by $6 million. The higher revenues were due to higher KWH deliveries (3.7% increase) and unit prices in the first quarter of 2005 as compared to the ~~remainder~~same period of 2004. Also contributing to the ~~decline in~~higher operating ~~revenues. The industrial customer sector deliveries increased 6.1% primarily~~revenues was a $10 million increase due to ~~JCP&L's largest industrial customer increasing its consumption by 18%.~~ Met-Ed’s assumption of transmission revenues (PJM congestion credit and FTR/ARR) from FES due to a change in the power supply agreement in the second quarter of 2004, which also resulted in higher transmission expenses discussed below. In addition, the higher operating revenues in the first quarter of 2005 included a $4 million payment received 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. This payment is credited to Met-Ed’s customers, resulting in no net earnings effect.

Changes in ~~distribution~~KWH deliveries in the first quarter of ~~2004~~2005 compared ~~with~~to the first quarter ~~of 2003~~2004 are summarized in the following table: Changes in Kilowatt-Hour Deliveries ---------------------------------------------------------- Increase (Decrease) Residential........................... 1.2% Commercial............................ (0.1)% Industrial............................ 6.1% ---------------------------------------------------------- Total Distribution Deliveries.................... 1.3% ==========================================================

Changes in KWH
Increase (Decrease)
Residential	2.2	%
Commercial	5.4	%
Industrial	3.9	%
Total KWH Deliveries	3.7	%

Operating Expenses and Taxes

Total operating expenses and taxes ~~decreased $115~~increased by $37 million in the first quarter of ~~2004 compared with~~2005 from the first quarter of ~~2003,~~2004. Purchased power costs increased in 2005 primarily due to ~~reduced~~an $18 million increase in two-party power purchases and a $2 million increase in NUG contract purchases, partially offset by a $14 million reduction in power purchased ~~power costs offset~~from FES. The net increase in ~~part by increased other operating expenses. The following table presents changes from~~KWH purchases was attributable to the ~~prior year by expense category. 106~~ Operating Expenses and Taxes - Changes ----------------------------------------------------------------- Increase (Decrease) (In millions) Fuel............................................. $ -- Purchased power.................................. (103) increase in retail generation sales.

Other operating costs............................ 17 ------------------------------------------------------------ Total operation and maintenance expenses....... (86) Provision for depreciation and amortization...... (2) General taxes.................................... -- Income taxes..................................... (27) ------------------------------------------------------------- Total operating expenses and taxes............. $(115) ============================================================= Lower purchased power costs increased in the first quarter of ~~2004, compared~~2005 primarily due to ~~the same quarter~~$27 million higher PJM ancillary transmission expenses, congestion charges, and FTR/ARR expenses. The transmission expense increase resulted from Met-Ed’s assumption of ~~2003, were due primarily to decreased kilowatt-hour purchases through two-party agreements. The increase in other~~PLR transmission related transactions discussed above. Other operating costs ~~was attributed~~also increased due to ~~JCP&L's accelerated reliability program (see Regulatory Matters). Net Interest Charges Net interest charges decreased~~higher storm-related and vegetation management costs.

Depreciation expenses increased due to higher estimated costs to decommission the Saxton nuclear plant and depreciation expense on property purchased from FESC in late 2004. Amortization of regulatory assets increased primarily due to increased amortization of regulatory assets being recovered through CTC rates, partially offset by lower amortization related to above market NUG costs.

110

General taxes increased by $2 million in the first quarter of ~~2004 compared with the first quarter of 2003, primarily~~2005 due to ~~debt redemptions since the end of the first quarter of 2003.~~ higher gross receipt taxes.

Capital Resources and Liquidity ~~- ------------------------------- JCP&L's~~

Met-Ed’s cash requirements in ~~2004~~2005 and thereafter, for operating expenses, construction expenditures and scheduled debt maturities are expected to be met ~~without increasing its net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities~~ with affiliates will be used to manage working capital requirements. Over the next two years, JCP&L expects to meet its contractual obligations with cash from operations. Thereafter, JCP&L expects to use a combination of cash from operations and funds from the capital markets.

Changes in Cash Position ~~JCP&L~~

As of March 31, 2005 and December 31, 2004, Met-Ed had ~~$0.3 million~~$120,000 of cash and cash ~~equivalents as of March 31, 2004 and December 31, 2003.~~ equivalents.

Cash Flows From Operating Activities

Cash provided from operating activities ~~during~~in the first quarter of 2005 and 2004 ~~compared to the first quarter of 2003~~ were as follows: ~~Operating~~

Operating Cash Flows	2005			2004
	*(In millions)*

Cash earnings⁽¹⁾	$	37		$	39
Working capital and other		(34	)		(38	)

Total Cash Flows from Operating Activities	$	3		$	1

⁽¹⁾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. 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.

	Three Months Ended
	March 31,
Reconciliation of Cash Earnings	2005			2004
	*(In millions)*

Net Income (GAAP)	$	16		$	18
Non-Cash Charges (Credits):
Provision for depreciation		12			10
Amortization of regulatory assets		29			25
Deferred costs recoverable as regulatory assets		(16	)		(17	)
Deferred income taxes and investment tax credits, net		--			2
Other non-cash expenses		(4	)		1
Cash earnings (Non-GAAP)	$	37		$	39

The $2 million decrease in cash earnings is described above and under "Results of Operations". The $4 million working capital change primarily resulted from changes of $64 million in receivables and $3 million in accrued interest, partially offset by changes of $56 million in accounts payable and $8 million in accrued taxes.

Cash Flows 2004 2003 ------------------------------------------------------------- (In millions) Cash earnings (1).................... $ 59 $94 Working capital and other............ 63 2 ------------------------------------------------------------- Total................................ $122 $96 ============================================================= (1) Includes net income, depreciation and amortization, deferred costs recoverable as regulatory assets, deferred income taxes and investment tax credits. From Financing Activities

Net cash provided from ~~operating~~financing activities ~~increased to $122~~was $19 million in the first quarter of ~~2004 from $96~~2005 compared to $127 million in the first quarter of ~~2003.~~2004. The ~~increase was due to a $61~~decrease primarily reflected $29 million ~~increase~~of short-term borrowings in funds provided from working capital and other changes, partially offset by a $35 million decrease in cash earnings. The increase in working capital reflects a $75 million decrease in cash requirements for accounts payable in 2004 as compared to 2003. The cash earnings decrease was mostly attributable to lower revenues. Cash Flows From Financing Activities In the first quarter of ~~2004, net~~2005 compared to last year’s issuance of $250 million of senior notes, partially offset by debt redemptions of $115 million in the first quarter of 2004. In addition, common stock dividends to FirstEnergy increased by $4 million in 2005.

As of March 31, 2005, Met-Ed had approximately $22 million of cash ~~used for financing activities of $88 million primarily reflected the redemption of $80~~and temporary investments (which included short-term notes receivable from associated companies) and $109 million of short-term borrowings $3outstanding. 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 long-term debt and $5 million of common stock dividend payments to FirstEnergy. In the first quarter of 2003, net cash used for financing activities totaled $99 million, primarily due to the redemption of debt and $89 million in common stock dividend payments to FirstEnergy. JCP&L may borrow from its affiliates on a short-term basis. JCP&L will not issueMet-Ed’s senior note indenture, no more first mortgage bonds ~~other than~~can be issued so long as ~~collateral for senior notes, since its senior note indenture prohibits (subject to certain exceptions) it from 107~~ ~~issuing any debt which is senior to~~ the senior ~~notes. Based upon applicable earnings coverage tests, JCP&L could not issue any first mortgage~~ bonds orare outstanding. Met-Ed had no restrictions on the issuance of preferred ~~stock~~stock.

111

In addition, Met-Ed has an $80 million customer receivables financing facility. The facility was undrawn as of March 31, ~~2004. On April 23, 2004, JCP&L issued $300 million of 5.625% Senior Notes due 2016. The proceeds of this transaction will~~2005; it expires June 30, 2005 and is expected to be used to redeem $40 million of 7.98% JCP&L Series C MTNs due 2023 and $50 million of 6.78% JCP&L Series C MTNs due 2005. The remaining proceeds will be used to fund the mandatory redemption of JCP&L's $160 million of 7.125% FMB due October 1, 2004 and to reduce short-term debt. JCP&Lrenewed.

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 first quarter of ~~2004~~2005 was ~~1.30%~~2.66%. On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2 from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that the lower ratings were prompted by: "1) high consolidated leverage with significant holding company debt, 2) a degree of regulatory uncertainty in the service territories in which the company operates, 3) risks associated with investigations of the causes of the August 2003 blackout, and related securities litigation, and 4) a narrowing of the ratings range for the FirstEnergy operating utilities, given the degree to which FirstEnergy increasingly manages the utilities as a single system and the significant financial interrelationship among the subsidiaries." On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy to restart the Davis-Besse nuclear plant was positive for credit quality because it would positively affect cash flow by eliminating replacement power costs and "demonstrating management's ability to overcome operational challenges." However, S&P did not change FirstEnergy's ratings or outlook because it stated that financial performance still "significantly lags expectations and management faces other operational hurdles." Cash Flows From Investing Activities Net cash used for investing activities totaled $34 million in the first quarter of 2004, compared with net cash provided from investing activities of $0.1 million in the first quarter of 2003. The $34 million increase was primarily due to the $1 million in loan payments made to associated companies in 2004 as compared to the $25 million in loan payments received from associated companies in 2003, as well as $4 million in increased property additions in 2004. During the last three quarters of 2004, capital requirements for property additions are expected to be about $122 million. JCP&L has additional requirements of approximately $160 million for maturing long-term debt during the remainder of 2004. These cash requirements (excluding debt refinancings) are expected to be satisfied from internal cash and short-term credit arrangements. Market Risk Information - ----------------------- JCP&L uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price fluctuations. FirstEnergy's Risk Policy Committee, comprised of executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent 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 future contracts. The derivatives are used for hedging purposes. Most of JCP&L's non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. The change in the fair value of commodity derivative contracts related to energy production during the first quarter of 2004 is summarized in the following table: 108 ~~Increase (Decrease) in the Fair Value of Commodity Derivative Contracts~~

(1) Includes $15 million in non-hedge commodity derivative contracts which are offset by a regulatory liability. (2) Represents the increase in value of existing contracts, settled contracts and changes in techniques/assumptions. Derivatives included on the Consolidated Balance Sheet as of March 31, 2004: Non-Hedge Hedge Total --------------------------------------------------------------------- (In millions) Current- Other Assets...................... $-- $ -- $-- Non-Current- Other Deferred Charges............ 15 -- 15 ------------------------------------------------------------------- Net assets........................ $15 $ -- $15 =================================================================== The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, JCP&L relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. JCP&L uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts by year are summarized in the following table:

(1) Broker quote sheets. (2) Includes $15 million from an embedded option that is offset by a regulatory liability and does not affect earnings. JCP&L performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of March 31, 2004. Equity Price Risk Included in JCP&L's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $72 million and $69 million as of March 31, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $7 million reduction in fair value as of March 31, 2004. 109 Outlook - ------- Beginning in 1999, all of JCP&L's customers were able to select alternative energy suppliers. JCP&L continues to deliver power to homes and businesses through its existing distribution system, which remains regulated. To support customer choice, rates were restructured into unbundled service charges and additional non-bypassable charges to recover stranded costs. 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. All of JCP&L's regulatory assets are expected to continue to be recovered under the provisions of the regulatory proceedings discussed below. JCP&L's regulatory assets totaled $2.5 billion and $2.6 billion as of March 31, 2004 and December 31, 2003, respectively. Regulatory Matters Under New Jersey transition legislation, all electric distribution companies were required to file rate cases to determine the level of unbundled rate components to become effective August 1, 2003. JCP&L's two August 2002 rate filings requested increases in base electric rates of approximately $98 million annually and requested the recovery of deferred energy costs that exceeded amounts being recovered under the current MTC and SBC rates; one proposed method of recovery of these costs is the securitization of the deferred balance. This securitization methodology is similar to the Oyster Creek securitization. In July 2003, the NJBPU announced its JCP&L base electric rate proceeding decision which reduced JCP&L's annual revenues by approximately $62 million effective August 1, 2003. The NJBPU decision also provided for an interim return on equity of 9.5% on JCP&L's rate base for the next six to twelve months. During that period, JCP&L will initiate another proceeding to request recovery of additional costs incurred to enhance system reliability. In that proceeding, the NJBPU could increase the return on equity to 9.75% or decrease it to 9.25%, depending on its assessment of the reliability of JCP&L's service. Any reduction would be retroactive to August 1, 2003. The revenue decrease in the decision consists of a $223 million decrease in the electricity delivery charge, a $111 million increase due to the August 1, 2003 expiration of annual customer credits previously mandated by the New Jersey transition legislation, a $49 million increase in the MTC tariff component, and a net $1 million increase in the SBC charge. The MTC allowed for the recovery of $465 million in deferred energy costs over the next ten years on an interim basis, thus disallowing $153 million of the $618 million provided for in a preliminary settlement agreement between certain parties. As a result, JCP&L recorded charges to net income for the year ended December 31, 2003, aggregating $185 million ($109 million net of tax) consisting of the $153 million deferred energy costs and other regulatory assets. JCP&L filed a motion for rehearing and reconsideration with the NJBPU on August 15, 2003 with respect to the following issues: (1) the disallowance of the $153 million deferred energy costs; (2) the reduced rate of return on equity; and (3) $42.7 million of disallowed costs to achieve merger savings. On October 10, 2003, the NJBPU held the motion in abeyance until the final NJBPU decision and order is issued. This is expected to occur in the second quarter of 2004. On July 5, 2003, JCP&L experienced a series of 34.5 kilo-volt sub-transmission line faults that resulted in outages on the New Jersey shore. The NJBPU instituted an investigation into these outages, and directed that a Special Reliability Master be hired to oversee the investigation. On December 8, 2003, the Special Reliability Master issued his Interim Report recommending that JCP&L implement a series of actions to improve reliability in the area affected by the outages. The NJBPU adopted the findings and recommendations of the Interim Report on December 17, 2003, and ordered JCP&L to implement the recommended actions on a staggered basis, with initial actions to be completed by March 31, 2004. JCP&L expects to spend $12.5 million implementing these actions during 2004. In late 2003, in accordance with a Stipulation concerning an August 2002 storm outage, the NJBPU engaged Booth & Associates to conduct an audit of the planning, operations and maintenance practices, policies and procedures of JCP&L. The audit was expanded to include the July 2003 outage and was completed in January 2004. JCP&L is awaiting the issuance of the final audit report and is unable to predict the outcome of the audit; no liability has been accrued as of March 31, 2004. On April 28, 2004, the NJBPU directed JCP&L to file testimony by the end of May 2004, either supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey ratepayers, or, alternatively, proposing a reduction, termination or capping of the funding. JCP&L cannot predict the outcome of this matter. Environmental Matters 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 be held liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets, 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. JCP&L has accrued liabilities aggregating approximately $45.6 million as of March 31, 2004. JCP&L accrues environmental liabilities only when it can conclude that it is probable that an obligation for such costs exists 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. 110 Power Outage On August 14, 2003, various states and parts of southern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. On April 5, 2004, the U.S. - -Canada Power System Outage Task Force released its final report on this outage. The final report supercedes the interim report that had been issued in November, 2003. In the final report, the Task Force concluded, among other things, that the problems leading to the outage began in FirstEnergy's Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14th power outage resulted from the coincidence on that afternoon of several events, including, 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 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 14th power outage and that it does not adequately address the underlying causes of the outage. FirstEnergy remains convinced that the outage cannot be explained by events on any one utility's system. The final report contains 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations relate to broad industry or policy matters while one relates to activities the Task Force recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy has undertaken several initiatives, some prior to and some since the August 14th power outage, to enhance reliability which are consistent with these and other recommendations and believes it will complete those relating to summer 2004 by June 30 (see Reliability Initiatives below). As many of these initiatives already were in process and budgeted in 2004, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its operations or financial results. FirstEnergy notes, however, that the 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. Reliability Initiatives On October 15, 2003, NERC issued a Near Term Action Plan that contained recommendations for all control areas and reliability coordinators with respect to enhancing system reliability. Approximately 20 of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that are recommended for completion by summer 2004. These initiatives principally relate to changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and, preparedness and operating center training. FirstEnergy presented a detailed compliance plan to NERC, which NERC subsequently endorsed on May 7, 2004, and the various initiatives are expected to be completed no later than June 30, 2004. On February 26-27, 2004, certain FirstEnergy companies participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC to review control area operations throughout much of the United States during 2004, is an independent review to identify areas for improvement. The final audit report was completed on April 30, 2004. The report identified positive observations and included various recommendations for improvement. FirstEnergy is currently reviewing the audit results and recommendations and expects to implement those relating to summer 2004 by June 30. Based on its review thus far, FirstEnergy believes that none of the recommendations identify a need for any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that NERC 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. On March 1, 2004, certain FirstEnergy companies filed, in accordance with a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. - Canada Power System Outage Task Force interim report. In particular, the filing addressed upgrades to FirstEnergy's control room computer hardware and software and enhancements to the training of control room operators. The PUCO will review the plan before determining the next steps, if any, in the proceeding. On April 22, 2004, FirstEnergy filed with FERC the results of the FERC-ordered independent study of part of Ohio's power grid. The study examined, among other things, the reliability of the transmission grid in critical points in the Northern Ohio area and the need, if any, for reactive power reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing the results of that study and expects to complete the implementation of recommendations relating to 2004 by this summer. Based on its review thus far, FirstEnergy believes that the study does not recommend any incremental material investment or upgrades to existing equipment. 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. 111 With respect to each of the foregoing initiatives, FirstEnergy has requested and NERC has agreed to provide, a technical assistance team of experts to provide ongoing guidance and assistance in implementing and confirming timely and successful completion. Legal Matters Various lawsuits, claims and proceedings related to our normal business operations are pending against us, the most significant of which are described herein. In July 1999, the Mid-Atlantic states experienced a severe heat storm 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 New Jersey 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. Since July 1999, this litigation has involved a substantial amount of legal discovery including interrogatories, request for production of documents, preservation and inspection of evidence, and depositions of the named plaintiffs and many JCP&L employees. In addition, there have been many motions filed and argued by the parties involving issues such as the primary jurisdiction and findings of the NJBPU, consumer fraud by JCP&L, strict product liability, class decertification, and the damages claimed by the plaintiffs. In January 2000, the NJ Appellate Division determined that the trial court has proper jurisdiction over this litigation. 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 products 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 have been appealed to the Appellation Division and oral argument is scheduled for May 2004. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of March 31, 2004. Critical Accounting Policies JCP&L prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of JCP&L's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. JCP&L's more significant accounting policies are described below. Regulatory Accounting JCP&L is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine JCP&L is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in New Jersey, a significant amount of regulatory assets have been recorded - $2.5 billion as of March 31, 2004. JCP&L regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. JCP&L continually monitors its derivative contracts to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, JCP&L enters into commodity contracts, as well as interest rate swaps, which increase the impact of derivative accounting judgments. 112 Revenue Recognition JCP&L follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, consumption by customer class and electricity provided from alternative suppliers. Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87 and SFAS 106, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to recent declines in corporate bond yields and interest rates in general, FirstEnergy reduced the assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first quarter of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Long-Lived Assets In accordance with SFAS 144, JCP&L periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, JCP&L recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). The calculation of future cash flows is based on assumptions, estimates and judgement about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. 113 Nuclear Decommissioning In accordance with SFAS 143, JCP&L recognizes an ARO for the future decommissioning of TMI-2. The ARO liability represents an estimate of the fair value of JCP&L's current obligation related to nuclear decommissioning. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. JCP&L used an expected cash flow approach (as discussed in FASB Concepts Statement No. 7) to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, JCP&L evaluates goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment were to be indicated, JCP&L would recognize a loss - calculated as the difference between the implied fair value of its goodwill and the carrying value of the goodwill. JCP&L's annual review was completed in the third quarter of 2003, with no impairment indicated. The forecasts used in JCP&L's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on JCP&L's future evaluations of goodwill. In the first quarter of 2004, JCP&L reduced goodwill by $3 million for interest received on a pre-merger income tax refund. As of March 31, 2004, JCP&L had $2 billion of goodwill. New Accounting Standards and Interpretations FSP 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" Issued January 12, 2004, FSP 106-1 permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Medicare Act. FirstEnergy elected to defer the effects of the Medicare Act due to the lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 as a result of a February 2, 2004 plan amendment that required remeasurement of the plan's obligations. See Note 2 for a discussion of the effect of the federal subsidy and plan amendment on the consolidated financial statements. FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" In December 2003, the FASB issued a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", referred to as FIN 46R, which requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, JCP&L adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. Adoption of FIN 46R did not have a material impact on JCP&L's financial statements for the quarter ended March 31, 2004. See Note 2 for a discussion of Variable Interest Entities. For the quarter ended March 31, 2004, JCP&L evaluated, among other entities, its power purchase agreements and determined that it is possible that six NUG entities might be considered variable interest entities. JCP&L has requested but not received the information necessary to determine whether these entities are VIEs or whether JCP&L is the primary beneficiary. In most cases, the requested information was deemed to be competitive and proprietary data. As such, JCP&L 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. JCP&L's purchased power costs from these entities during the first quarters of 2004 and 2003 were $28 million and $34 million, respectively. JCP&L is required to continue to make exhaustive efforts to obtain the necessary information in future periods and is unable to determine the possible impact of consolidating any such entity without this information. 114 ~~METROPOLITAN EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited)~~

~~METROPOLITAN EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)~~

~~METROPOLITAN EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)~~

REPORT OF INDEPENDENT ACCOUNTANTS 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 March 31, 2004, and the related consolidated statements of income and cash flows for each of the three-month periods ended March 31, 2004 and 2003. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. 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 generally accepted auditing standards, 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 auditing standards generally accepted in the United States of America, the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2003, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company's change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 1(E) 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 8 to those consolidated financial statements) dated February 25, 2004, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2003, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio May 7, 2004 118 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 provides regulated transmission and distribution services in eastern Pennsylvania. Pennsylvania customers are able to choose their electricity suppliers as a result of legislation which restructured the electric utility industry. Met-Ed's regulatory plan required unbundling 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 and maintains PLR obligations to customers who elect to retain Met-Ed as their power supplier. Results of Operations - --------------------- Net income in the first quarter of 2004 increased to $18 million from $17 million in the first quarter of 2003. Results improved in the first quarter of 2004 due to increased retail electric sales revenues and lower interest charges, partially offset by higher purchased power costs. Operating revenues increased by $10 million, or 3.9% in the first quarter of 2004 compared with the first quarter of 2003. The higher revenues primarily resulted from increased distribution revenues of $10 million from electricity throughput as a result of higher unit prices and increased consumption by the commercial and industrial sectors -- reflecting the effects of an improving regional economy. Higher retail generation kilowatt-hour sales of 7.9% increased operating revenues by $2 million. The increase was primarily due to more commercial and industrial customers returning to Met-Ed as their electric service provider. Sales of electric generation by alternative suppliers as a percent of total sales delivered in Met-Ed's franchise area decreased to 10.3% in the first quarter of 2004 from 15.8% in the same period of 2003. Wholesale revenues decreased by $1 million, reflecting lower sales to affiliated companies and to the wholesale market. Changes in distribution deliveries in the first quarter of 2004 compared to the first quarter 2003 are summarized in the following table: Changes in Kilowatt-Hour Sales --------------------------------------------------- Increase (Decrease) Distribution Deliveries: Residential............................. (0.6)% Commercial.............................. 3.9% Industrial.............................. 1.5% --------------------------------------------------- Total Distribution Deliveries............. 1.3% =================================================== Operating Expenses and Taxes Total operating expenses and taxes increased $10 million in the first quarter of 2004 from the first quarter of 2003. Purchased power costs were $8 million higher due to increased PLR kilowatt-hour purchases from FES (due to increased generation sales requirements), partially offset by reduced above-market NUG costs. Other operating costs were lower in 2004 in part due to lower employee benefit costs. Depreciation and amortization expenses were higher due to increased amortization of regulatory assets related to CTC revenue recovery. General taxes increased due to gross receipts taxes and higher payroll taxes related to the transfer of employees to Met-Ed from GPUS. Net Interest Charges Net interest charges continued to trend lower, decreasing by $2 million in the first quarter of 2004 from the same quarter of last year, reflecting redemptions and refinancings since the end of the first quarter of 2003. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, Met-Ed recorded an after-tax credit to net income of $217,000. The cumulative adjustment for unrecognized depreciation and accretion offset by the reduction in the existing decommissioning liabilities was a $371,000 increase to income, or $217,000 net of income taxes. 119 Capital Resources and Liquidity - ------------------------------- Met-Ed expects to meet its cash requirements in 2004 for operating expenses, construction expenditures, scheduled debt maturities and optional debt redemptions without increasing its net debt and preferred stock outstanding. Over the next three years, Met-Ed expects to meet its contractual obligations with cash from operations. Thereafter, Met-Ed expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position As of March 31, 2004, Met-Ed had $120,000 of cash and cash equivalents compared with $121,000 as of December 31, 2003. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash provided from operating activities in the first quarter of 2004 and 2003 were as follows: Operating Cash Flows 2004 2003 ------------------------------------------------------------- (In millions) Cash earnings (1).................... $ 39 $ 41 Working capital and other............ (38) (8) ------------------------------------------------------------- Total................................ $ 1 $ 33 ============================================================= (1) Includes net income, depreciation and amortization, deferred costs recoverable as regulatory assets, deferred income taxes, investment tax credits and major noncash credits. Net cash provided from operating activities decreased $32 million in the first quarter of 2004 from the first quarter of 2003 as a result of a $30 million decrease from working capital and other changes and a $2 million decrease in cash earnings. The largest factor contributing to the change in working capital was a $25 million decrease in accounts payable. Cash Flows From Financing Activities In the first quarter of 2004, net cash provided from financing activities of $127 million reflected the issuance of $250 million of senior notes, partially offset by the redemption of $50 million of long-term debt and $65 million of short-term debt, and a common stock dividend of $5 million to FirstEnergy. Net cash provided from financing activities totaled $185 million in the first quarter of 2003, due to the issuance of $250 million of senior notes, partially offset by the redemption of $40 million of long-term debt and $23 million of short-term debt. As of March 31, 2004, Met-Ed had approximately $127 million of cash and temporary investments (which include short-term notes receivable from associated companies) and no outstanding short-term borrowings. Met-Ed will not issue first mortgage bonds since its senior note indentures prohibit (subject to certain exceptions) it from issuing any debt which is senior to the senior notes. Because Met-Ed satisfied the provisions of its senior note indenture for the release of all FMBs held as collateral for senior notes in March 2004, it is no longer required to issue FMBs as collateral for future issuances of senior notes and therefore not limited as to the amount of senior notes it may issue. Met-Ed had no restrictions on the issuance of preferred stock. 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. Available bank borrowings include $1.75 billion from FirstEnergy's and OE's revolving credit facilities. 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 first quarter of 2004 was 1.30%. In March 2004, Met-Ed completed an on-balance sheet, receivable financing transaction which allows it to borrow up to $80 million. The borrowing rate is based on bank commercial paper rates. Met-Ed is required to pay an annual facility fee of 0.30% on the entire finance limit. The facility was undrawn as of March 31, 2004. This facility matures on March 29, 2005. Met-Ed's

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 ~~of its~~ securities is stable. ~~120~~ On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2 from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that the lower ratings were prompted by: "1) high consolidated leverage with significant holding company debt, 2) a degree of regulatory uncertainty in the service territories in which the company operates, 3) risks associated with investigations of the causes of the August 2003 blackout, and related securities litigation, and 4) a narrowing of the ratings range for the FirstEnergy operating utilities, given the degree to which FirstEnergy increasingly manages the utilities as a single system and the significant financial interrelationship among the subsidiaries."

Cash Flows From Investing Activities

In the first quarter of ~~2004,~~2005, net cash used in investing activities totaled ~~$128~~$22 million, compared to ~~$20~~$128 million in the first quarter of ~~2003.~~2004. The ~~change~~decrease resulted from a ~~$108~~$114 million ~~increase~~decrease in ~~loan payments~~loans to associated companies offset in part by ~~slightly lower~~a $7 million increase in property additions. Expenditures for property additions primarily support ~~Met-Ed's~~Met-Ed’s energy delivery operations.

During the remaining quarters of ~~2004,~~2005, capital requirements for property additions are expected to be about ~~$46~~$52 million. Met-Ed has additional requirements of approximately ~~$136~~$37 million for maturing long-term debt during the remainder of ~~2004.~~2005. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. ~~Off-Balance Sheet Arrangements - ------------------------------ As~~

Met-Ed's capital spending for the period 2005 through 2007 is expected to be about $205 million for property additions and energy delivery related improvements, of ~~March 31, 2004, off-balance sheet arrangements include certain statutory business trusts created by Met-Ed~~which approximately $67 million applies to issue trust preferred securities aggregating $93 million. These trusts were included in the consolidated financial statements of Met-Ed prior to the adoption of FIN 46R, but have subsequently been deconsolidated under FIN 46R (see Note 2 - Variable Interest Entities). Deconsolidation has not resulted in any change in outstanding debt. 2005.

Market Risk Information ~~- -----------------------~~

Met-Ed uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price fluctuations. ~~FirstEnergy's~~FirstEnergy’s Risk Policy Committee, comprised of ~~executive officers, exercises an independent risk oversight function~~members of senior management, provides general management to ~~ensure compliance with corporate~~ risk management ~~policies and prudent risk management practices.~~ activities throughout the Company.

Commodity Price Risk

Met-Ed 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 ~~future~~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. ~~The change in the~~As of March 31, 2005, Met-Ed’s commodity derivative contract was an embedded option with a fair value of ~~commodity derivative contracts related to energy production during the first quarter~~$27 million. A decrease of ~~2004 is summarized~~$5 million in the ~~following table: 121~~ ~~Increase (Decrease)~~value of this asset was recorded as a decrease in ~~the Fair Value of Commodity Derivative Contracts~~

~~(1) Includes $30 million in non-hedge commodity derivative contracts which are offset by~~ a regulatory ~~liability. (2) Represents the increase in value of existing contracts, settled contracts~~liability and, ~~changes in techniques/assumptions. Derivatives included~~therefore, had no impact on the Consolidated Balance Sheet as of March 31, 2004: Non-Hedge Hedge Total ------------------------------------------------------------------- (In millions) Current- Other Assets...................... $-- $ -- $-- Non-Current- Other Deferred Charges............ 30 -- 30 ------------------------------------------------------------------- Net assets........................ $30 $ -- $30 =================================================================== 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, Met-Ed relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Met-Ed uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. ~~Sources of information for the~~The valuation of the derivative ~~contracts by year are summarized~~contract at March 31, 2005 is shown using prices from sources in the following table:

Source of Information
- Fair Value by Contract Year	2005		2006		2007		2008		2009		Thereafter		Total
	*(In millions)*
Prices based on external sources⁽¹⁾	$	5	$	4	$	--	$	--	$	--	$	--	$	9
Prices based on models		--		--		6		5		3		4		18

Total	$	5	$	4	$	6	$	5	$	3	$	4	$	27

⁽¹⁾ Broker quote sheets. ~~(2) Includes $30 million from an embedded option that is offset by a regulatory liability and does not affect earnings.~~

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Met-Ed performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of March 31, ~~2004.~~ 2005.

Equity Price Risk

Included in Met-Ed's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately ~~$119~~$131 million and ~~$114~~$134 million as of March 31, ~~2004~~2005 and December 31, ~~2003,~~2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a ~~$12~~$13 million reduction in fair value as of March 31, ~~2004. Outlook - ------- Beginning in 1999,~~2005.

OUTLOOK

The electric industry continues to transition to a more competitive environment and all of Met-Ed's customers ~~were able to~~can select alternative energy suppliers. Met-Ed continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. ~~The PPUC authorized Met-Ed's rate restructuring plan, establishing~~Customer rates have been restructured into separate ~~charges for transmission, distribution, generation and stranded cost recovery, which is recovered through a CTC. Customers electing~~components to obtain power from an alternative supplier have their bills reduced based on the regulated generation component, and the customers receive a generation charge from the alternative 122 ~~supplier.~~support customer choice. Met-Ed has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain ~~limits, which~~limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties.

Regulatory Matters

Beginning in 1999, all of Met-Ed's customers had a choice for electric generation suppliers. Met-Ed's customer rates were restructured to itemize (unbundle) the current price of electricity into its component elements - including generation, transmission, distribution and stranded cost recovery. In the event customers obtain power from an alternative source, the generation portion of Met-Ed's rates is ~~referred to as its PLR obligation.~~ excluded from their bill and the customers receive a generation charge from the alternative supplier.

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. ~~All of~~ Met-Ed's regulatory assets ~~are expected to continue to be recovered under the provisions of its regulatory plan. Met-Ed's regulatory assets totaled $990 million and $1.03 billion~~ as of March 31, ~~2004~~2005 and December 31, ~~2003,~~2004 were $750 million and $693 million, respectively. Regulatory Matters In June 2001, the PPUC approved the Settlement Stipulation with all of the major parties in the combined merger and rate proceedings which approved the FirstEnergy/GPU merger and provided PLR deferred accounting treatment for energy costs, permitting

Met-Ed to defer, for future recovery, energy costs in excess of amounts reflected in its capped generation rates retroactive to January 1, 2001. This PLR deferral accounting procedure was later reversed in a February 2002 Commonwealth Court of Pennsylvania decision. The court decision affirmed the PPUC decision regarding approval of the merger, remanding the decision to the PPUC only with respect to the issue of merger savings. Met-Ed established a $103.0 million reserve in 2002 for its PLR deferred energy costs incurred prior to its acquisition by FirstEnergy, reflecting the potential adverse impact of the then pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court decision. The reserve increased goodwill by an aggregate net of tax amount of $60.3 million. On April 2, 2003, the PPUC remanded the issue relating to merger savings to the ALJ for hearings, directed Met-Ed to file a position paper on the effect of the Commonwealth Court order on the Settlement Stipulation and allowed other parties to file responses to the position paper. Met-Ed filed a letter with the ALJ on June 11, 2003, voiding the Stipulation in its entirety and reinstating Met-Ed's restructuring settlement previously approved by the PPUC. On October 2, 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety. The PPUC directed Met-Ed to file tariffs within thirty days of the order to reflect the CTC rates and shopping credits that were in effect prior to the June 21, 2001 order to be effective upon one day's notice. In response to that order, Met-Ed filed these supplements to its tariffs to become effective October 24, 2003. On October 8, 2003, Met-Ed filed a petition for clarification relating to the October 2, 2003 order on two issues: to establish June 30, 2004 as the date to fully refund the NUG trust fund and to clarify that the ordered accounting treatment regarding the CTC rate/shopping credit swap should follow the ratemaking, and that the PPUC's findings would not impair its rights to recover all of its stranded costs. On October 9, 2003, ARIPPA (an intervenor in the proceedings) petitioned the PPUC to direct Met-Ed to reinstate accounting for the CTC rate/shopping credit swap retroactive to January 1, 2002. Several other parties also filed petitions. On October 16, 2003, the PPUC issued a reconsideration order granting the date requested by Met-Ed for the NUG trust fund refund and, denying Met-Ed's other clarification requests and granting ARIPPA's petition with respect to the retroactive accounting treatment of the changes to the CTC rate/shopping credit swap. On October 22, 2003, Met-Ed filed an Objection with the Commonwealth Court asking that the Court reverse the PPUC's finding that requires Met-Ed to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. On October 27, 2003, one Commonwealth Court judge issued an Order denying Met-Ed's objection without explanation. Due to the vagueness of the Order, Met-Ed, on October 31, 2003, filed an Application for Clarification with the judge. Concurrent with this filing, Met-Ed, in order to preserve its rights, also filed with the Commonwealth Court both a Petition for Review of the PPUC's October 16 and October 22 Orders, and an application for reargument, if the judge, in his clarification order, indicates that Met-Ed's objection was intended to be denied on the merits. In addition to these findings, Met-Ed, in compliance with the PPUC's Orders, filed revised PPUC quarterly reports for the twelve months ended December 31, 2001 and 2002, and for the first two quarters of 2003, reflecting balances consistent with the PPUC's findings in their Orders. Effective September 1, 2002, Met-Ed agreed to purchasepurchases a portion of its PLR requirements from FES through a wholesale power ~~sale~~sales agreement. The PLR sale ~~will be~~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 ~~assumed~~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. FES has hedged most of Met-Ed's unfilled PLR on-peak obligation through 2004 and a portion of 2005, the period during which deferred accounting was previously allowed under the PPUC's order. Met-Ed is authorized to continue deferring differences between NUG contract costs and current market prices. ~~123~~ ~~In late 2003,~~

On January 12, 2005, Met-Ed filed a request with the PPUC ~~issued~~for deferral of transmission-related costs beginning January 1, 2005, estimated to be approximately $4 million per month.

See Note 13 to the consolidated financial statements for further details and a ~~Tentative Order implementing new~~complete discussion of regulatory matters in Pennsylvania including a more detailed discussion of reliability ~~benchmarks and standards. In connection therewith,~~initiatives, including actions by the PPUC, ~~commenced a rulemaking procedure to amend~~that impacts Met-Ed.

Environmental Matters

Met-Ed accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably determine the ~~Electric Service Reliability Regulations to implement these new benchmarks,~~amount of such costs. Unasserted claims are reflected in Met-Ed's determination of environmental liabilities and create additional reporting on reliability. Although neither the Tentative Order nor the Reliability Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. The comment period for both the Tentative Order and the Proposed Rulemaking Order has closed. Met-Ed is currently awaiting the PPUC to issue a final order in both matters. The order will determine (1) the standards and benchmarks to be utilized, and (2) the details requiredare accrued in the ~~quarterly~~period that they are both probable and annual reports. On January 16, 2004, the PPUC initiated a formal investigation of whether Met-Ed's "service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring" in Pennsylvania. Discovery has commenced in the proceeding and Met-Ed's testimony is due May 14, 2004. Hearings are scheduled to begin August 3, 2004 in this investigation and the ALJ has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order by year end of 2004. Met-Ed is unable to predict the outcome of the investigation or the impact of the PPUC order. Environmental Matters reasonably estimable.

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Met-Ed 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 ~~be held~~are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance ~~Sheets,~~Sheet as of March 31, 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. ~~Met-Ed has~~Included in Other Noncurrent Liabilities are accrued liabilities aggregating approximately ~~$50,000~~$48,000 as of March 31, ~~2004. Met-Ed accrues environmental liabilities only when it can conclude that it is probable that an obligation~~2005.

Other Legal Proceedings

There are various lawsuits, claims (including claims for ~~such costs exists~~asbestos exposure) and ~~can reasonably determine the amount of such costs. Unasserted claims~~proceedings related to Met-Ed's normal business operations pending against Met-Ed. The most significant are ~~reflected in Met-Ed's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable. Power Outage~~ described below.

On August 14, 2003, various states and parts of southern Canada experienced a widespread power ~~outage. That outage~~outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. ~~On April 5, 2004, the~~The U.S. - ~~-Canada~~Canada Power System Outage Task ~~Force released its~~Force’s final report in April 2004 on ~~this outage. The final report supercedes~~ the ~~interim report that had been issued in November, 2003. In the final report, the Task Force~~outages concluded, among other things, that the problems leading to the ~~outage~~outages began in ~~FirstEnergy's~~FirstEnergy’s Ohio service ~~area. Specifically,~~area.Specifically, the final report concludes, among other things, that the initiation of the August ~~14th~~14, 2003 power ~~outage~~outages resulted from ~~the coincidence on that afternoon of several events, including,~~ 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~~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~~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 ~~14th~~14, 2003 power ~~outage~~outages and that it does not adequately address the underlying causes of the ~~outage.~~outages. FirstEnergy remains convinced that the ~~outage~~outages cannot be explained by events on any one utility's system. The final report ~~contains~~contained 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations ~~relate~~related to broad industry or policy matters while one, ~~relates~~including subparts, related to activities the Task Force ~~recommends~~recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and ~~ECAR.~~other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy ~~has undertaken~~implemented several initiatives, ~~some~~both prior to and ~~some~~ since the August ~~14th~~14, 2003 power ~~outage, to enhance reliability~~outages, which ~~are~~were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and ~~believes it will complete those relating to summer 2004 by June 30 (see Reliability Initiatives below).~~collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these initiatives already were in process, ~~and budgeted in 2004,~~ FirstEnergy does not believe that any incremental expenses associated with additional initiatives ~~undertaken during~~completed in 2004 ~~will have~~had a material effect on its continuing operations or financial results. FirstEnergy notes, however, that the 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. ~~Reliability Initiatives On October 15, 2003, NERC issued~~FirstEnergy has not accrued a ~~Near Term Action Plan that contained recommendations for all control areas and reliability coordinators with respect to enhancing system reliability. Approximately 20~~liability as of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that are recommended for completion by summer 2004. These initiatives principally relate to changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and, preparedness and operating center training. 124 FirstEnergy presented a detailed compliance plan to NERC, which NERC subsequently endorsed on May 7, 2004, and the various initiatives are expected to be completed no later than June 30, 2004. On February 26-27, 2004, certain FirstEnergy companies participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC to review control area operations throughout much of the United States during 2004, is an independent review to identify areas for improvement. The final audit report was completed on April 30, 2004. The report identified positive observations and included various recommendations for improvement. FirstEnergy is currently reviewing the audit results and recommendations and expects to implement those relating to summer 2004 by June 30. Based on its review thus far, FirstEnergy believes that none of the recommendations identify a needMarch 31, 2005 for any ~~incremental material investment or upgrades to existing equipment.~~expenditures in excess of those actually incurred through that date.

One complaint was filed on August 25, 2004 against FirstEnergy notes, however, that NERC 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. On March 1, 2004, certain FirstEnergy companies filed, in accordance with a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. - Canada Power System Outage Task Force interim report.New York State Supreme Court. In particular, the filing addressed upgrades to FirstEnergy's control room computer hardware and software and enhancements to the training of control room operators. The PUCO will review the plan before determining the next steps, if any,this case, several plaintiffs in the proceeding. On April 22, 2004, FirstEnergy filed with FERC the results of the FERC-ordered independent study of part of Ohio's power grid. The study examined, among other things, the reliability of the transmission grid in critical points in the Northern OhioNew York City metropolitan area ~~and the need, if any, for reactive power reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing the results of~~allege that study and expects to complete the implementation of recommendations relating to 2004 by this summer. Based on its review thus far, FirstEnergy believes that the study does not recommend any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different viewthey suffered damages as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. With respect to each of the foregoing initiatives, FirstEnergy has requested and NERC has agreed to provide, a technical assistance team of experts to provide ongoing guidance and assistance in implementing and confirming timely and successful completion. Legal Matters Various lawsuits, claims and proceedings related to our normal business operations are pending against Met-Ed, the most significant of which are described above. Critical Accounting Policies Met-Ed prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of Met-Ed's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Met-Ed's more significant accounting policies are described below. Regulatory Accounting Met-Ed is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine Met-Ed is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the ~~changing~~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 ~~framework~~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 Pennsylvania, a significant amount of regulatory assets have been recorded - $990 million as of March 31, 2004. Met-Ed regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associatedconnection with these ~~assets relates~~proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.

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New Accounting Standards and Interpretations

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

On March 30, 2005, the FASB issued this interpretation to potentially adverse legislative, judicial or regulatory actions in the future. Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are 125 ~~documented. Derivative contracts that are determined to fall within~~clarify the scope and timing of ~~SFAS 133, as amended, must be recorded at their~~liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair ~~value. Active market prices are not always available to determine~~value of an asset retirement obligation that is conditional on a future event, if the fair value of the ~~later years of a contract, requiring that various assumptions and estimates~~liability can be ~~used in their valuation. Met-Ed continually monitors its derivative contracts~~reasonably estimated. In instances where there is insufficient information to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, Met-Ed enters into commodity contracts, as well as interest rate swaps, which increaseestimate the ~~impact of derivative accounting judgments. Revenue Recognition Met-Ed follows~~liability, the ~~accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered~~obligation is to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, consumption by customer class and electricity provided from alternative suppliers. Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87 and SFAS 106, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to recent declines in corporate bond yields and interest rates in general, FirstEnergy reduced the assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first quarter of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Long-Lived Assets In accordance with SFAS 144, Met-Ed periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must 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. FirstEnergy is currently evaluating the effect this standard will have on the financial statements. If

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 ~~has 126~~ ~~occurred, Met-Ed recognizes a loss - calculated as~~is other-than-temporary, the ~~difference between the carrying~~investment must be measured at fair value and the ~~estimated fair value~~impairment loss recognized in earnings. The recognition and measurement provisions of the asset (discounted future net cash flows). The calculation of future cash flows is based on assumptions, estimates and judgement about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. Nuclear Decommissioning In accordance with SFAS 143, Met-Ed recognizes an ARO for the future decommissioning of TMI-2. The ARO liability represents an estimate of the fair value of Met-Ed's current obligation related to nuclear decommissioning. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. Met-Ed used an expected cash flow approach (as discussed in FASB Concepts Statement No. 7) to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, Met-Ed evaluates goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairmentEITF 03-1, which were to be ~~indicated, Met-Ed would recognize a loss - calculated as~~effective for periods beginning after June 15, 2004, were delayed by the ~~difference between~~issuance of FSP EITF 03-1-1 in September 2004. During the ~~implied fair value~~period of its goodwill and the carrying value of the goodwill. Met-Ed's annual review was completed in the third quarter of 2003, with no impairment indicated. The forecasts used in Met-Ed's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on Met-Ed's future evaluations of goodwill. In the first quarter of 2004, Met-Ed reduced goodwill by $4 million for interest received on a pre-merger income tax refund. As of March 31, 2004, Met-Ed had $880 million of goodwill. New Accounting Standards and Interpretations - -------------------------------------------- FSP 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" Issued January 12, 2004, FSP 106-1 permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Medicare Act.delay, FirstEnergy elected to defer the effects of the Medicare Act due to the lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 as a result of a February 2, 2004 plan amendment that required remeasurement of the plan's obligations. See Note 2 for a discussion of the effect of the federal subsidy and plan amendment on the consolidated financial statements. FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" In December 2003, the FASB issued a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", referred to as FIN 46R, which requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, Met-Ed adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. Adoption of FIN 46R did not have a material impact on Met-Ed's financial statements for the quarter ended March 31, 2004. See Note 2 for a discussion of Variable Interest Entities. For the quarter ended March 31, 2004, Met-Ed evaluated, among other entities, its power purchase agreements and determined that it is possible that one NUG entity might be considered a variable interest entity. Met-Ed has requested but not received the information necessary to determine whether this entity is a VIE or whether Met-Ed is the primary beneficiary. In most cases, the requested information was deemed to be competitive and proprietary data. As such, Met-Ed applied the scope exception that exempts enterprises unable to obtain the necessary informationwill continue 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. Met-Ed's purchased power costs from this entity during the first quartersits investments as required by existing authoritative guidance.

115

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,

	2005			2004

	*(In thousands)*

OPERATING REVENUES	$	293,929		$	256,445

OPERATING EXPENSES AND TAXES:
Purchased power		150,277			156,376
Other operating costs		53,793			39,908
Provision for depreciation		12,506			11,438
Amortization of regulatory assets		13,185			13,651
General taxes		18,206			16,962
Income taxes		15,792			2,563
Total operating expenses and taxes		263,759			240,898

OPERATING INCOME		30,170			15,547

OTHER INCOME (EXPENSE) (net of income taxes)		736			(84	)

NET INTEREST CHARGES:
Interest on long-term debt		7,459			7,447
Allowance for borrowed funds used during construction		(125	)		(70	)
Deferred interest		--			190
Other interest expense		2,188			2,237
Net interest charges		9,522			9,804

NET INCOME	$	21,384		$	5,659

OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gain on derivative hedges		16			--
Unrealized gain (loss) on available for sale securities		(3	)		8
Other comprehensive income (loss)		13			8
Income tax related to other comprehensive income		(6	)		(3	)
Other comprehensive income (loss), net of tax		7			5

TOTAL COMPREHENSIVE INCOME	$	21,391		$	5,664


The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company arean integral part of these statements.

116

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2005			2004
	*(In thousands)*
ASSETS
UTILITY PLANT:
In service	$	1,962,547		$	1,981,846
Less - Accumulated provision for depreciation		756,126			776,904
		1,206,421			1,204,942
Construction work in progress		25,837			22,816
		1,232,258			1,227,758
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		108,252			109,620
Non-utility generation trusts		96,738			95,991
Long-term notes receivable from associated companies		14,164			14,001
Other		14,589			18,746
		233,743			238,358
CURRENT ASSETS:
Cash and cash equivalents		35			36
Notes receivable from associated companies		10,271			7,352
Receivables-
Customers (less accumulated provisions of $4,435,000 and $4,712,000,
respectively, for uncollectible accounts)		128,530			121,112
Associated companies		48,645			97,528
Other		15,098			12,778
Prepayments and other		42,317			7,198
		244,896			246,004
DEFERRED CHARGES:
Goodwill		887,103			888,011
Regulatory assets		277,520			200,173
Other		12,293			13,448
		1,176,916			1,101,632
	$	2,887,813		$	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		1,205,948			1,205,948
Accumulated other comprehensive loss		(52,806	)		(52,813	)
Retained earnings		62,453			46,068
Total common stockholder's equity		1,321,407			1,305,015
Long-term debt and other long-term obligations		478,695			481,871
		1,800,102			1,786,886
CURRENT LIABILITIES:
Currently payable long-term debt		11,525			8,248
Short-term borrowings-
Associated companies		69,693			241,496
Other		170,000			--
Accounts payable-
Associated companies		28,338			56,154
Other		29,542			25,960
Accrued taxes		18,204			7,999
Accrued interest		15,276			9,695
Other		18,166			23,750
		360,744			373,302
NONCURRENT LIABILITIES:
Power purchase contract loss liability		441,255			382,548
Asset retirement obligation		67,482			66,443
Accumulated deferred income taxes		49,680			37,318
Retirement benefits		119,115			118,247
Other		49,435			49,008
		726,967			653,564
COMMITMENTS AND CONTINGENCIES (Note 12)
	$	2,887,813		$	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.

117

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31,

	2005			2004

	*(In thousands)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	21,384		$	5,659
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		12,506			11,438
Amortization of regulatory assets		13,185			13,651
Deferred costs recoverable as regulatory assets		(19,433	)		(17,993	)
Deferred income taxes and investment tax credits, net		2,446			25,242
Accrued retirement benefit obligation		868			2,802
Accrued compensation, net		(2,630	)		2,255
Decrease (Increase) in operating assets:
Receivables		39,145			(12,129	)
Prepayments and other current assets		(35,119	)		(47,054	)
Increase (Decrease) in operating liabilities:
Accounts payable		(24,234	)		(10,738	)
Accrued taxes		10,205			(6,483	)
Accrued interest		5,581			2,636
Other		(217	)		3,654
Net cash provided from (used for) operating activities		23,687			(27,060	)

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		--			150,000
Redemptions and Repayments-
Long-term debt		(13	)		(104	)
Short-term borrowings, net		(1,803	)		(61,326	)
Dividend Payments-
Common stock		(5,000	)		--
Net cash provided from (used for) financing activities		(6,816	)		88,570

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(15,393	)		(11,194	)
Non-utility generation trust contribution		--			(50,614	)
Loans to associated companies, net		(3,082	)		(71	)
Other, net		1,603			369
Net cash used for investing activities		(16,872	)		(61,510	)

Net change in cash and cash equivalents		(1	)		--
Cash and cash equivalents at beginning of period		36			36
Cash and cash equivalents at end of period	$	35		$	36


The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are anintegral part of these statements.

118

Report of 2004 and 2003 were $16 million and $15 million, respectively. Met-Ed is required to continue to make exhaustive efforts to obtain the necessary information in future periods and is unable to determine the possible impact of consolidating any such entity without this information. 127 ~~PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME (Unaudited)~~
Three Months Ended March 31, --------------------------- 2004 2003 ---------- ---------- (In thousands) OPERATING REVENUES.............................................................. $ 256,445 $ 254,876 ---------- ---------- OPERATING EXPENSES AND TAXES: Purchased power.............................................................. 156,376 155,146 Other operating costs........................................................ 39,908 43,077 ---------- ---------- Total operation and maintenance expenses................................. 196,284 198,223 Provision for depreciation and amortization.................................. 25,089 25,337 General taxes................................................................ 16,962 15,744 Income taxes................................................................. 2,563 2,893 ---------- ---------- Total operating expenses and taxes....................................... 240,898 242,197 ---------- ---------- OPERATING INCOME................................................................ 15,547 12,679 OTHER EXPENSE................................................................... (84) (192) ----------- ---------- INCOME BEFORE NET INTEREST CHARGES.............................................. 15,463 12,487 ---------- ---------- NET INTEREST CHARGES: Interest on long-term debt................................................... 7,447 7,339 Allowance for borrowed funds used during construction........................ (70) (81) Deferred interest............................................................ 190 (996) Other interest expense ...................................................... 2,237 143 Subsidiary's preferred stock dividend requirements........................... -- 1,888 ---------- ---------- Net interest charges..................................................... 9,804 8,293 ---------- ---------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................ 5,659 4,194 Cumulative effect of accounting change (net of income taxes of $777,000) (Note 2) -- 1,096 ---------- ---------- NET INCOME...................................................................... $ 5,659 $ 5,290 ========== ========== ~~The preceding Notes to Consolidated Financial Statements as they relate to the Pennsylvania Electric Company are an integral part of these statements.~~ ~~128~~
~~PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)~~
March 31, December 31, 2004 2003 ------------------------------- (In thousands) ASSETS UTILITY PLANT: In service..................................................................... $1,976,743 $1,966,624 Less-Accumulated provision for depreciation.................................... 796,606 785,715 ---------- ---------- 1,180,137 1,180,909 Construction work in progress.................................................. 29,374 29,063 ---------- ---------- 1,209,511 1,209,972 ---------- ---------- OTHER PROPERTY AND INVESTMENTS: Non-utility generation trusts.................................................. 94,660 43,864 Nuclear plant decommissioning trusts........................................... 105,615 102,673 Long-term notes receivable from associated companies........................... 13,865 13,794 Other.......................................................................... 19,117 19,635 ---------- ---------- 233,257 179,966 --------- ---------- CURRENT ASSETS: Cash and cash equivalents...................................................... 36 36 Receivables- Customers (less accumulated provisions of $5,872,000 and $5,833,000 respectively, for uncollectible accounts).................................. 117,489 124,462 Associated companies......................................................... 107,346 88,598 Other (less accumulated provisions of $388,000 and $399,000 respectively, for uncollectible accounts).................................. 16,121 15,767 Prepayments and other.......................................................... 49,564 2,511 ---------- ---------- 290,556 231,374 ---------- ---------- DEFERRED CHARGES: Regulatory assets.............................................................. 458,560 497,219 Goodwill....................................................................... 894,491 898,547 Accumulated deferred income tax benefits....................................... - 16,642 Other.......................................................................... 19,568 18,523 ---------- ---------- 1,372,619 1,430,931 ---------- ---------- $3,105,943 $3,052,243 ========== ========== CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common stockholder's equity- Common stock, par value $20 per share, authorized 5,400,000 shares, 5,290,596 shares outstanding............................................... $ 105,812 $ 105,812 Other paid-in capital........................................................ 1,215,667 1,215,667 Accumulated other comprehensive loss......................................... (42,180) (42,185) Retained earnings............................................................ 23,697 18,038 ---------- ---------- Total common stockholder's equity.......................................... 1,302,996 1,297,332 Long-term debt and other long-term obligations................................. 588,255 438,764 ---------- ---------- 1,891,251 1,736,096 ---------- ---------- CURRENT LIABILITIES: Currently payable long-term debt .............................................. 125,605 125,762 Short-term borrowings- Associated companies......................................................... 17,185 78,510 Accounts payable- Associated companies......................................................... 56,391 55,831 Other........................................................................ 28,893 40,192 Accrued taxes................................................................. 2,222 8,705 Accrued interest............................................................... 15,330 12,694 Other.......................................................................... 25,068 21,764 ---------- ---------- 270,694 343,458 ---------- ---------- NONCURRENT LIABILITIES: Accumulated deferred income taxes.............................................. 7,717 -- Accumulated deferred investment tax credits.................................... 9,691 9,936 Asset retirement obligation.................................................... 106,631 105,089 Nuclear fuel disposal costs.................................................... 19,010 18,968 Power purchase contract loss liability......................................... 629,965 670,482 Retirement benefits............................................................ 147,882 145,081 Other.......................................................................... 23,102 23,133 ---------- ---------- 943,998 972,689 ---------- ---------- COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................ ---------- ---------- $3,105,943 $3,052,243 ========== ========== ~~The preceding Notes to Consolidated Financial Statements as they relate to the Pennsylvania Electric Company are an integral part of these balance sheets.~~ ~~129~~
~~PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)~~
Three Months Ended March 31, --------------------------- 2004 2003 --------- -------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income .................................................................. $ 5,659 $ 5,290 Adjustments to reconcile net income to net cash from operating activities- Provision for depreciation and amortization........................... 25,089 25,337 Deferred costs recoverable as regulatory assets....................... (17,993) (11,656) Deferred income taxes, net............................................ 25,487 (41,640) Investment tax credits, net........................................... (245) (247) Accrued retirement benefit obligations................................ 2,802 -- Accrued compensation, net............................................. 2,255 62 Cumulative effect of accounting change (Note 2)....................... -- (1,873) Receivables........................................................... (12,129) 5,440 Accounts payable...................................................... (10,738) 8,666 Accrued taxes......................................................... (6,483) 27,284 Accrued interest...................................................... 2,636 5,679 Prepayments and other current assets.................................. (47,054) (34,778) Other................................................................. 3,654 (7,152) -------- -------- Net cash used for operating activities.............................. (27,060) (19,588) -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt.......................................................... 150,000 -- Redemptions and Repayments- Long-term debt.......................................................... (104) -- Short-term borrowings, net.............................................. (61,326) (90,427) -------- --------- Net cash provided from (used for) financing activities.................... 88,570 (90,427) -------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions........................................................ (11,194) (6,312) Non-utility generation trusts withdrawals (contributions)................. (50,614) 106,327 Loans to associated companies............................................. (71) -- Other, net................................................................ 369 -- -------- -------- Net cash provided from (used for) investing activities.............. (61,510) 100,015 --------- -------- Net change in cash and cash equivalents...................................... -- (10,000) Cash and cash equivalents at beginning of period ............................ 36 10,310 -------- -------- Cash and cash equivalents at end of period................................... $ 36 $ 310 ======== ======== ~~The preceding Notes to Consolidated Financial Statements as they relate to the Pennsylvania Electric Company are an integral part of these statements.~~ ~~130~~
~~REPORT OF INDEPENDENT ACCOUNTANTS~~ 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 March 31, ~~2004,~~2005, and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, ~~2004~~2005 and ~~2003.~~2004. These interim financial statements are the responsibility of the ~~Company's~~Company’s management.

We previously audited, in accordance with ~~auditing~~the standards ~~generally accepted in~~of the ~~United States of America,~~Public Company Accounting Oversight Board (United States), the consolidated balance sheet ~~and the consolidated statement of capitalization~~ as of December 31, ~~2003,~~2004, and the related consolidated statements of income, capitalization, common ~~stockholder's~~stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, ~~(not presented herein),~~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~~Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note ~~1(E)~~2(G) to those consolidated financial statements and the ~~Company's~~Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 86 to those consolidated financial statements) dated ~~February 25, 2004,~~March 7, 2005, we expressed an unqualified ~~opinion on those~~opinions thereon. The consolidated financial ~~statements.~~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 ~~condensed~~ consolidated balance sheet information as of December 31, ~~2003,~~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

May ~~7, 2004 131~~ 3, 2005

119

PENNSYLVANIA ELECTRIC COMPANY ~~MANAGEMENT'S~~

MANAGEMENT’S DISCUSSION AND

ANALYSIS OF RESULTS OF OPERATIONS

AND FINANCIAL CONDITION

Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec ~~provides~~conducts business in northern, western and south central Pennsylvania, providing regulated transmission and distribution services. Penelec also provides generation services ~~in western Pennsylvania. Pennsylvania~~to those customers ~~are able~~electing to ~~choose~~retain Penelec as their ~~electricity suppliers as a result of legislation which restructured the electric utility industry. Penelec's regulatory plan required unbundling~~power supplier. Penelec has unbundled the price for electricity into its component elements - including generation, transmission, distribution and transition charges. Penelec continues to deliver power to homes and businesses through its existing distribution system and maintains PLR obligations to customers who elect to retain Penelec as their power supplier.

Results ~~from~~of Operations ~~- -----------------------~~

Net income in the first quarter of ~~2004~~2005 increased to ~~$5.7~~$21 million, compared to ~~$5.3~~$6 million in the first quarter of ~~2003. Net~~2004. The increase resulted from higher operating revenues and lower purchased power costs, partially offset by higher other operating costs and general taxes.

Operating revenues increased by $37 million in the first quarter of 2005 compared to the first quarter of 2004, primarily due to higher transmission, retail generation and distribution revenues. Transmission revenues increased $23 million as a result of Penelec's assumption of transmission revenues from FES due to a change in the power supply agreement with FES in the second quarter of 2004, which also resulted in higher transmission expenses discussed further below. In addition, the higher first quarter 2005 operating revenues included a $2 million payment received 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. This payment is credited to Penelec’s customers, resulting in no net earnings effect.

Retail generation revenues increased by $9 million, principally from increased generation sales to industrial and commercial customers (industrial - $5 million and commercial - $4 million) reflecting volume sales increases of 12.5% and 6.8%, respectively, and higher unit costs. Industrial KWH sales increased despite higher customer shopping in this sector. Sales by alternative suppliers as a percent of total industrial sales delivered in Penelec’s franchise area increased by 4.0 percentage points, while commercial customer shopping remained constant in the first quarter of 2005. Residential generation revenues showed a slight increase of $0.4 million and residential KWH sales were nearly unchanged in the first quarter of 2005 as compared to last year.

Distribution revenues increased by $3 million in the first quarter of 2005 as compared to the same period of 2004, primarily on higher deliveries to the commercial and industrial sectors. The higher commercial and industrial revenues of $2 million and $1 million, respectively, reflected the effect of increased KWH deliveries partially offset by lower composite unit prices.

Changes in electric distribution deliveries in the first quarter 2005 compared to the first quarter 2004 are summarized in the following table:

Changes in KWH Deliveries	2005
*Increase (Decrease)*
Residential		0.5	%
Commercial		6.9	%
Industrial		18.4	%
Total KWH Deliveries		8.0	%

Operating Expenses and Taxes

Total operating expenses and taxes increased by $23 million or 9.5% in the first quarter 2005 from the first quarter of 2004. Purchased power costs decreased by $6 million or 3.9% in the first quarter of 2005, compared to the first quarter 2004. The decrease was due primarily to lower unit costs slightly offset by increased KWH purchased to meet increased retail generation sales requirements. Other operating costs increased by $14 million or 34.8% in the first quarter 2005, compared to first quarter 2004. That increase was primarily dueto increased transmission expenses in 2005, which were assumed by Penelec due to a change in the power supply agreement with FES discussed above. In addition, there were higher storm-related contractor costs in the first quarter of 2005.

120

General taxes increased due to the higher Pennsylvania gross receipts taxes in first quarter of 2005 compared to same period in 2004. Income taxes increased due to higher pre-tax income in the first quarter of 2003 included an after-tax credit of $1.1 million from the cumulative effect of an accounting change due to the adoption of SFAS 143. Income before the cumulative effect was $5.7 million in the first three months of 2004,2005 compared to $4.2 million for the same period of 2003. The increase in net income was the result of higher operating revenues and lower operating costs -- partially offset by a lower level of deferred interest costs. Operating revenues increased by $1.6 million or 0.6% in the first quarter of 2004 compared with the same period in 2003. The higher revenues resulted from increased distribution revenues offset by lower retail generation revenues. Revenues from electricity throughput increased by $9 million as a result of higher unit prices which were partially offset by slightly lower distribution deliveries compared to the prior year. Penelec's retail generation kilowatt-hour sales increased 1.5% reflecting higher residential and commercial sales of 3.5% and 0.5%, respectively. Retail generation sales revenue decreased $5.3 million reflecting lower unit prices, which offset the generation sales increase as more customers returned from alternative suppliers. Although wholesale kilowatt-hour sales increased 121.3%, the volume was minimal for the first quarters of 2004 and 2003 and revenues increased only slightly. Changes in electric generation sales and distribution deliveries in the first quarter of 2004 from the first quarter of 2003 are summarized in the following table: Changes in Kilowatt-Hour Sales --------------------------------------------------- Increase (Decrease) Electric Generation: Retail................................ 1.5% Wholesale............................. 121.3% ------------------------------------------------- Total Electric Generation Sales......... 1.9% ================================================= Distribution Deliveries: Residential........................... 3.4% Commercial............................ 0.5% Industrial............................ (4.5)% -------------------------------------------------- Total Distribution Deliveries........... (0.4)% ================================================== 132 Operating Expenses and Taxes Total operating expenses and taxes decreased $1 million or 0.5% in the first quarter of 2004 from the first quarter of 2003, primarily due to lower other operating costs partially offset by increased purchased power costs and general taxes. The following table presents changes during the first quarter of 2004 from the same period in 2003 for operating expenses and taxes. Operating Expenses and Taxes - Changes ----------------------------------------------------------------- Increase (Decrease) (In millions) Purchased power ................................. $ 1 Other operating costs............................ (3) ----------------------------------------------------------------- Total operation and maintenance expenses....... (2) Provision for depreciation and amortization...... -- General taxes.................................... 1 Income taxes..................................... -- ----------------------------------------------------------------- Total operating expenses and taxes............. $ (1) ================================================================= Lower other operating costs in the first quarter of 2004, compared with the same quarter of 2003, were due to reduced postretirement benefit plan expenses, lower uncollectible customer accounts and transmission expenses. Purchased power costs increased due primarily to increased PLR purchases from FES, partially offset by reduced two-party energy purchases. General taxes increased due to higher payroll taxes from the transfer of employees to Penelec from GPUS. Net Interest Charges Net interest charges increased by $1.5 million in the first quarter of 2004 compared with the first quarter of 2003, reflecting a lower level of deferred interest costs. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, Penelec recorded an after-tax credit to net income of $1.1 million. The cumulative adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice depreciating non-regulated generation assets using a cost of removal component was an $1.9 million increase to income, or $1.1 million net of income taxes. 2004.

Capital Resources and Liquidity ~~- ------------------------------- Penelec's~~

Penelec’s cash requirements in ~~2004~~2005 and thereafter, for operating expenses, construction expenditures and scheduled debt maturities are expected to be met without increasing its net debt and preferred stock outstanding. Over the next two years, Penelec expects to meet its contractual obligations with cash from operations. Thereafter, Penelec expects to useby a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

As of March 31, ~~2004 and December 31, 2003,~~2005, Penelec had ~~$36,000~~$35,000 of cash and cash ~~equivalents.~~ 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 ~~Cash used by~~

Net cash provided from operating activities in the first quarter of 2004, compared with the first quarter of 2003 were as follows: Operating Cash Flows 2004 2003 ------------------------------------------------------------- (In millions) Cash earnings (1).................... $ 43 $ (25) Working capital and other............ (70) 5 ------------------------------------------------------------- Total................................ $(27) $ (20) ============================================================= (1) Includes net income, depreciation and amortization, deferred costs recoverable as regulatory assets, deferred income taxes, investment tax credits and pension changes. Net cash used for operating activities increased to $27was $24 million in the first quarter of ~~2004 from $20~~2005, compared to net cash used for operating activities of $27 million in 2004, summarized as follows:

Operating Cash Flows	2005			2004
	*(In millions)*

Cash earnings⁽¹⁾	$	28		$	43
Working capital and other		(4	)		(70	)
Total	$	24		$	(27	)

⁽¹⁾Cash earnings is a non-GAAP measure (see reconciliation below).

Cash earnings (in the ~~same period~~table above) are not a measure of ~~2003. In 2004, the increase was due to the increase~~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 ~~working capital requirements (primarily from changes in accounts receivable and payable) offset by an increase~~evaluating its cash-based operating performance.

Reconciliation of Cash Earnings	2005			2004
	*(In millions)*

Net Income (GAAP)	$	21		$	6
Non-Cash Charges (Credits):
Provision for depreciation		13			11
Amortization of regulatory assets		13			14
Deferred costs recoverable as regulatory assets		(19	)		(18	)
Deferred income taxes and investment tax credits		2			25
Other non-cash expenses		(2	)		5
Cash earnings (Non-GAAP)	$	28		$	43

The $15 million decrease in cash earnings ~~from higher deferred income taxes.~~ is described above and under "Results of Operations". This was partially offset by a $66 million change in working capital principally due to changes in receivables, prepayments and accrued taxes, partially offset by a change in the accounts payable.

Cash Flows From Financing Activities

Net cash used for financing activities was $7 million in the first quarter of 2005 compared to net cash provided from financing activities of $89 million in the first quarter of 2004. The net change reflects the absence of 2004 ~~compared~~long-term debt financing of $150 million, a $60 million decrease in debt redemptions and $5 million of common stock dividend payments to ~~net cash used for financing activities of $90 million~~FirstEnergy in the first quarter of ~~2003, represents the issuance in March 2004 of $150~~2005.

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Penelec had approximately $10 million of ~~long-term debt partially offset by a decrease in~~cash and temporary investments (which include short-term ~~borrowings. The proceeds~~notes receivable from ~~the $150 million issuance were used to redeem $125 133~~ ~~million principal amount of senior notes that matured on April 1, 2004~~associated companies) and ~~to repay short-term borrowings. As of March 31, 2004, Penelec had $17~~approximately $240 million of short-term indebtedness ~~compared~~as of March 31, 2005. Penelec has authorization from the SEC to ~~$79~~incur short-term debt of up to $250 million at(including the ~~end of 2003. Penelec may borrow from its affiliates on a short-term basis.~~utility money pool). Penelec will not issue ~~first mortgage bonds~~FMB other than as collateral for senior notes, since its senior note ~~indenture prohibits~~indentures prohibit (subject to certain exceptions) itPenelec from issuing any debt which is senior to the senior notes. As of March 31, ~~2004,~~2005, Penelec ~~had~~did not have the ~~capability~~ability to issue ~~$6.5 million of~~ additional senior notes based upon ~~first mortgage bond~~FMB collateral. Penelec ~~had~~has no restrictions on the issuance of preferred stock.

In ~~March 2004,~~addition, Penelec ~~completed an on-balance sheet, receivable~~has a $75 million customer receivables financing ~~transaction which allows it to borrow up to $75 million. The borrowing rate is based on bank commercial paper rates. Penelec is required to pay an annual~~ facility ~~fee of 0.30% on the entire finance limit. The facility~~that was ~~undrawn~~drawn for $70 million as of March 31, ~~2004. This~~2005. The facility ~~matures~~expires on ~~March 29, 2005. Penelec's~~June 30, 2005, and is expected to be renewed.

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 first quarter of 2005 was 2.66%.

Penelec’s access to capital markets and costs of financing are dependent on the ratings of its securities and ~~the securities~~that of FirstEnergy. The ratings outlook on all ~~of its~~ securities is stable. On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured debt to Baa3 from Baa2 and downgraded the senior secured debt of JCP&L, Met-Ed and Penelec to Baa1 from A2. Moody's also downgraded the preferred stock rating of JCP&L to Ba1 from Baa2 and the senior unsecured rating of Penelec to Baa2 from A2. The ratings of OE, CEI, TE and Penn were confirmed. Moody's said that the lower ratings were prompted by: "1) high consolidated leverage with significant holding company debt, 2) a degree of regulatory uncertainty in the service territories in which the company operates, 3) risks associated with investigations of the causes of the August 2003 blackout, and related securities litigation, and 4) a narrowing of the ratings range for the FirstEnergy operating utilities, given the degree to which FirstEnergy increasingly manages the utilities as a single system and the significant financial interrelationship among the subsidiaries."

Cash Flows From Investing Activities ~~Net cash~~

Cash used for investing activities ~~were~~was $17 million in the first quarter of 2005 compared to $62 million in the first quarter of ~~2004, compared~~2004. The decrease was primarily due to ~~net cash provided from investing activities totaling $100 million~~the absence in ~~the first quarter~~2005 of ~~2003. The net cash used for investing activities resulted from~~ a ~~refunding payment of~~ $51 million repayment to ~~a NUG trust fund and increased property additions in 2004. In the first quarter of 2003, net cash provided from investing activities resulted from $106 million of withdrawals from~~ the NUG trust fund in 2004, partially offset by ~~property additions. Expenditures~~increased loans of $3 million to associated companies. In both periods, cash outflows for property additions ~~primarily~~were made to support ~~Penelec's energy delivery operations.~~ the distribution of electricity.

During the remaining quarters of ~~2004,~~2005, capital requirements for property additions are expected to be about ~~$54~~$73 million. Penelec has additional requirements of approximately ~~$125~~$11 million for maturing long-term debt during the remainder of ~~2004. These cash~~2005. Those requirements ~~(excluding debt refinancings)~~ are expected to be satisfied from internal cash and short-term credit arrangements. ~~Off-Balance Sheet Arrangements - ------------------------------ As~~

Penelec’s capital spending for the period 2005-2007 is expected to be about $272 million for property additions and improvements, of ~~March 31, 2004, Penelec's off-balance sheet arrangements included certain statutory business trusts created by Penelec~~which about $89 million applies to issue trust preferred securities of $92 million. These trusts were included in Penelec's financial statements prior to the adoption of FIN 46R, but have subsequently been deconsolidated under FIN 46R (see Note 2 - Variable Interest Entities). This deconsolidation has not resulted in any change in outstanding debt. 2005.

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~~FirstEnergy’s Risk Policy Committee, comprised of ~~executive officers, exercises an independent risk~~members of senior management, provides general management oversight ~~function~~ to ~~ensure compliance with corporate~~ risk management ~~policies and prudent risk management practices. 134~~ 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 ~~future~~futures contracts. The derivatives are used for hedging purposes. ~~Most of Penelec's~~Penelec’s non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. ~~The change in the~~As of March 31, 2005, Penelec’s commodity derivatives contract was an embedded option with a fair value of ~~commodity derivative contracts related to energy production during the first quarter~~$14 million. A decrease of ~~2004 is summarized~~$1 million in the ~~following table:~~ ~~Increase (Decrease)~~value of this asset was recorded as a decrease in ~~the Fair Value of Commodity Derivative Contracts~~

~~(1) Includes $14 million in non-hedge commodity derivative contracts which are offset by~~ a regulatory ~~liability. Derivatives included~~liability and, therefore, had no impact on the Consolidated Balance Sheet as of March 31, 2004: Non-Hedge Hedge Total --------------------------------------------------------------------- (In millions) Current- Other Assets...................... $-- $ -- $-- Non-Current- Other Deferred Charges............ 15 -- 15 --------------------------------------------------------------------- Net assets........................ $15 $ -- $15 ===================================================================== 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, Penelec relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Penelec uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. ~~Sources of information for the~~The valuation of the derivative ~~contracts by year are summarized~~contract at March 31, 2005 uses prices from sources shown in the following table:

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Source of Information
—Fair Value by Contract Year	2005		2006		2007		2008		2009		Thereafter		Total
	*(In millions)*

Prices based on external sources⁽¹⁾	$	3	$	3	$	--	$	--	$	--	$	--	$	6
Prices based on models		--		--		2		2		2		2		8

Total	$	3	$	3	$	2	$	2	$	2	$	2	$	14

⁽¹⁾Broker quote sheets. ~~(2) Includes $14 million from an embedded option that is offset by a regulatory liability and does not affect earnings.~~

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 March 31, ~~2004.~~ 2005.

Equity Price Risk

Included in ~~Penelec's~~ nuclear decommissioning ~~trust investments~~trusts are marketable equity securities carried at their ~~market~~current fair value of approximately ~~$55~~$58 million and ~~$54~~$60 million as of March 31, ~~2004~~2005 and December 31, ~~2003,~~2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $6 million reduction in fair value as of March 31, ~~2004. 135~~ 2005.

Outlook ~~- ------- Beginning in 1999,~~

The electric industry continues to transition to a more competitive environment and all of Penelec's customers ~~were able to~~can select alternative energy suppliers. Penelec continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. ~~The PPUC authorized Penelec's rate restructuring plan, establishing~~Customer rates have been restructured into separate ~~charges for transmission, distribution, generation and stranded cost recovery, which is recovered through a CTC. Customers electing~~components to ~~obtain power from an alternative supplier have their bills reduced based on the regulated generation component, and the customers receive a generation charge from the alternative supplier.~~support customer choice. Penelec has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain ~~limits, which~~limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties.

Regulatory Matters

Beginning in 1999, all of Penelec's customers had a choice for electric generation suppliers. Penelec's customer rates were restructured to itemize (unbundle) the current price of electricity into its component elements - including generation, transmission, distribution and stranded cost recovery. In the event customers obtain power from an alternative source, the generation portion of Penelec's rates is ~~referred to as its PLR obligation.~~ excluded from their bill and the customers receive a generation charge from the alternative supplier.

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. ~~All of~~ Penelec's regulatory assets ~~are expected to continue to be recovered under the provisions of the regulatory plan as discussed below. Penelec's regulatory assets totaled $459 million and $497 million~~ as of March 31, ~~2004~~2005 and December 31, ~~2003,~~2004 were $278 million and $200 million, respectively. Regulatory Matters In June 2001, the PPUC approved the Settlement Stipulation with all of the major parties in the combined merger and rate proceedings which approved the FirstEnergy/GPU merger and provided PLR deferred accounting treatment for energy costs, permitting

Penelec to defer, for future recovery, energy costs in excess of amounts reflected in its capped generation rates retroactive to January 1, 2001. This PLR deferral accounting procedure was later reversed in a February 2002 Commonwealth Court of Pennsylvania decision. The court decision affirmed the PPUC decision regarding approval of the merger, remanding the decision to the PPUC only with respect to the issue of merger savings. Penelec established a $111.1 million reserve in 2002 for its PLR deferred energy costs incurred prior to its acquisition by FirstEnergy, reflecting the potential adverse impact of the then pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court decision. The reserve increased goodwill by an aggregate net of tax amount of $65.0 million. On April 2, 2003, the PPUC remanded the issue relating to merger savings to the ALJ for hearings, directed Penelec to file a position paper on the effect of the Commonwealth Court order on the Settlement Stipulation and allowed other parties to file responses to the position paper. Penelec filed a letter with the ALJ on June 11, 2003, voiding the Stipulation in its entirety and reinstating Penelec's restructuring settlement previously approved by the PPUC. On October 2, 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety. The PPUC directed Penelec to file tariffs within thirty days of the order to reflect the CTC rates and shopping credits that were in effect prior to the June 21, 2001 order to be effective upon one day's notice. In response to that order, Penelec filed these supplements to its tariffs to become effective October 24, 2003. On October 8, 2003, Penelec filed a petition for clarification relating to the October 2, 2003 order on two issues: to establish June 30, 2004 as the date to fully refund the NUG trust fund and to clarify that the ordered accounting treatment regarding the CTC rate/shopping credit swap should follow the ratemaking, and that the PPUC's findings would not impair its rights to recover all of its stranded costs. On October 9, 2003, ARIPPA (an intervenor in the proceedings) petitioned the PPUC to direct Penelec to reinstate accounting for the CTC rate/shopping credit swap retroactive to January 1, 2002. Several other parties also filed petitions. On October 16, 2003, the PPUC issued a reconsideration order granting the date requested by Penelec for the NUG trust fund refund and, denying Penelec's other clarification requests and granting ARIPPA's petition with respect to the retroactive accounting treatment of the changes to the CTC rate/shopping credit swap. On October 22, 2003, Penelec filed an Objection with the Commonwealth Court asking that the Court reverse the PPUC's finding that requires Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. On October 27, 2003, one Commonwealth Court judge issued an Order denying Penelec's objection without explanation. Due to the vagueness of the Order, Penelec, on October 31, 2003, filed an Application for Clarification with the judge. Concurrent with this filing, Penelec, in order to preserve its rights, also filed with the Commonwealth Court both a Petition for Review of the PPUC's October 16 and October 22 Orders, and an application for reargument, if the judge, in his clarification order, indicates that Penelec's objection was intended to be denied on the merits. In addition to these findings, Penelec, in compliance with the PPUC's Orders, filed revised PPUC quarterly reports for the twelve months ended December 31, 2001 and 2002, and for the first two quarters of 2003, reflecting balances consistent with the PPUC's findings in their Orders. 136 ~~Effective September 1, 2002, Penelec agreed to purchase~~purchases a portion of its PLR requirements from FES through a wholesale power ~~sale~~sales agreement. The PLR sale ~~will be~~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 ~~assumed~~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. FES has hedged most of Penelec's unfilled PLR on-peak obligation through 2004 and a portion of 2005, the period during which deferred accounting was previously allowed under the PPUC's order. Penelec is authorized to continue deferring differences between NUG contract costs and current market prices. ~~In late 2003,~~

On January 12, 2005, Penelec filed a request with the PPUC ~~issued~~for deferral of transmission-related costs beginning January 1, 2005, estimated to be approximately $4 million per month.

See Note 13 to the consolidated financial statements for further details and a ~~Tentative Order implementing new~~complete discussion of regulatory matters in Pennsylvania, including a more detailed discussion of reliability ~~benchmarks and standards. In connection therewith,~~initiatives, including actions by the PPUC ~~commenced a rulemaking procedure to amend~~that impact Penelec.

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Environmental Matters

Penelec accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably determine the ~~Electric Service Reliability Regulations to implement these new benchmarks,~~amount of such costs. Unasserted claims are reflected in Penelec's determination of environmental liabilities and create additional reporting on reliability. Although neither the Tentative Order nor the Reliability Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. The comment period for both the Tentative Order and the Proposed Rulemaking Order has closed. Penelec is currently awaiting the PPUC to issue a final order in both matters. The order will determine (1) the standards and benchmarks to be utilized, and (2) the details requiredare accrued in the ~~quarterly~~period that they are both probable and annual reports. On January 16, 2004, the PPUC initiated a formal investigation of whether Penelec's "service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring" in Pennsylvania. Discovery has commenced in the proceeding and Penelec's testimony is due May 14, 2004. Hearings are scheduled to begin August 3, 2004 in this investigation and the ALJ has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order by year end of 2004. Penelec is unable to predict the outcome of the investigation or the impact of the PPUC order. Environmental Matters reasonably estimable.

Penelec 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 ~~be held~~are liable on a joint and several basis. ~~Therefore, environmental liabilities that~~

Other Legal Proceedings

There are ~~considered probable have been recognized on the Consolidated Balance Sheets, based on estimates of the total costs of cleanup,~~various lawsuits, claims (including claims for asbestos exposure) and proceedings related to Penelec's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. Penelec has accrued liabilities aggregating approximately $30,000 as of March 31, 2004. Penelec accrues environmental liabilities only when it can conclude that it is probable that an obligation for such costs exists and can reasonably determine the amount of such costs. Unasserted claimsnormal business operations pending against Penelec. The most significant are ~~reflected in Penelec's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable. Power Outage~~ described below.

On August 14, 2003, various states and parts of southern Canada experienced a widespread power ~~outage. That outage~~outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. ~~On April 5, 2004, the~~The U.S. - ~~-Canada~~Canada Power System Outage Task ~~Force released its~~Force’s final report in April 2004 on ~~this outage. The final report supercedes~~ the ~~interim report that had been issued in November, 2003. In the final report, the Task Force~~outages concluded, among other things, that the problems leading to the ~~outage~~outages began in ~~FirstEnergy's~~FirstEnergy’s Ohio service ~~area. Specifically,~~area.Specifically, the final report concludes, among other things, that the initiation of the August ~~14th~~14, 2003 power ~~outage~~outages resulted from ~~the coincidence on that afternoon of several events, including,~~ 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~~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~~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 ~~14th~~14, 2003 power ~~outage~~outages and that it does not adequately address the underlying causes of the ~~outage.~~outages. FirstEnergy remains convinced that the ~~outage~~outages cannot be explained by events on any one utility's system. The final report ~~contains~~contained 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations ~~relate~~related to broad industry or policy matters while one, ~~relates~~including subparts, related to activities the Task Force ~~recommends~~recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and ~~ECAR.~~other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy ~~has undertaken~~implemented several initiatives, ~~some~~both prior to and ~~some~~ since the August ~~14th~~14, 2003 power ~~outage, to enhance reliability~~outages, which ~~are~~were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and ~~believes it will complete those relating to summer 2004 by June 30 (see Reliability Initiatives below).~~collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these initiatives already were in process, ~~and budgeted in 2004,~~ FirstEnergy does not believe that any incremental expenses associated with additional initiatives ~~undertaken during~~completed in 2004 ~~will have~~had a material effect on its continuing operations or financial results. ~~137~~ FirstEnergy notes, however, that the 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. ~~Reliability Initiatives On October 15, 2003, NERC issued~~FirstEnergy has not accrued a ~~Near Term Action Plan that contained recommendations for all control areas and reliability coordinators with respect to enhancing system reliability. Approximately 20~~liability as of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that are recommended for completion by summer 2004. These initiatives principally relate to changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and, preparedness and operating center training. FirstEnergy presented a detailed compliance plan to NERC, which NERC subsequently endorsed on May 7, 2004, and the various initiatives are expected to be completed no later than June 30, 2004. On February 26-27, 2004, certain FirstEnergy companies participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC to review control area operations throughout much of the United States during 2004, is an independent review to identify areas for improvement. The final audit report was completed on April 30, 2004. The report identified positive observations and included various recommendations for improvement. FirstEnergy is currently reviewing the audit results and recommendations and expects to implement those relating to summer 2004 by June 30. Based on its review thus far, FirstEnergy believes that none of the recommendations identify a needMarch 31, 2005 for any ~~incremental material investment or upgrades to existing equipment.~~expenditures in excess of those actually incurred through that date.

One complaint was filed on August 25, 2004 against FirstEnergy notes, however, that NERC 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. On March 1, 2004, certain FirstEnergy companies filed, in accordance with a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. - Canada Power System Outage Task Force interim report.New York State Supreme Court. In particular, the filing addressed upgrades to FirstEnergy's control room computer hardware and software and enhancements to the training of control room operators. The PUCO will review the plan before determining the next steps, if any,this case, several plaintiffs in the proceeding. On April 22, 2004, FirstEnergy filed with FERC the results of the FERC-ordered independent study of part of Ohio's power grid. The study examined, among other things, the reliability of the transmission grid in critical points in the Northern OhioNew York City metropolitan area ~~and the need, if any, for reactive power reinforcements during summer 2004 and 2005. FirstEnergy is currently reviewing the results of~~allege that study and expects to complete the implementation of recommendations relating to 2004 by this summer. Based on its review thus far, FirstEnergy believes that the study does not recommend any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different viewthey suffered damages as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. With respect to each of the foregoing initiatives, FirstEnergy has requested and NERC has agreed to provide, a technical assistance team of experts to provide ongoing guidance and assistance in implementing and confirming timely and successful completion. Legal Matters Various lawsuits, claims and proceedings related to Penelec's normal business operations are pending against it, the most significant of which are described above. Critical Accounting Policies Penelec prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of Penelec's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Penelec's more significant accounting policies are described below. Regulatory Accounting Penelec is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine Penelec is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the ~~changing~~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 ~~framework~~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 Pennsylvania, a significant amount of regulatory assets have been recorded - $459 million as of March 31, 2004. Penelec regularly reviews these assets to assess their ultimate 138 ~~recoverability within the approved regulatory guidelines. Impairment risk associated~~connection with these ~~assets relates~~proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.

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New Accounting Standards and Interpretations

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

On March 30, 2005, the FASB issued this interpretation to potentially adverse legislative, judicial or regulatory actions in the future. Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall withinclarify the scope and timing of ~~SFAS 133, as amended, must be recorded at their~~liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair ~~value. Active market prices are not always available to determine~~value of an asset retirement obligation that is conditional on a future event, if the fair value of the ~~later years of a contract, requiring that various assumptions and estimates~~liability can be ~~used in their valuation. Penelec continually monitors its derivative contracts~~reasonably estimated. In instances where there is insufficient information to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, Penelec enters into commodity contracts, as well as interest rate swaps, which increaseestimate the ~~impact of derivative accounting judgments. Revenue Recognition Penelec follows~~liability, the ~~accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered~~obligation is to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, consumption by customer class and electricity provided from alternative suppliers. Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87 and SFAS 106, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to recent declines in corporate bond yields and interest rates in general, FirstEnergy reduced the assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first quarter of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% in later years. 139 In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Long-Lived Assets In accordance with SFAS 144, Penelec periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must 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. FirstEnergy is currently evaluating the effect this standard will have on the financial statements. If

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 ~~has occurred, Penelec recognizes a loss - calculated as~~is other-than-temporary, the ~~difference between the carrying~~investment must be measured at fair value and the ~~estimated fair value~~impairment loss recognized in earnings. The recognition and measurement provisions of the asset (discounted future net cash flows). The calculation of future cash flows is based on assumptions, estimates and judgement about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. Nuclear Decommissioning In accordance with SFAS 143, Penelec recognizes an ARO for the future decommissioning of TMI-2. The ARO liability represents an estimate of the fair value of Penelec's current obligation related to nuclear decommissioning. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. Penelec used an expected cash flow approach (as discussed in FASB Concepts Statement No. 7 to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, Penelec evaluates goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairmentEITF 03-1, which were to be ~~indicated Penelec would recognize a loss - calculated as~~effective for periods beginning after June 15, 2004, were delayed by the ~~difference between~~issuance of FSP EITF 03-1-1 in September 2004. During the ~~implied fair value~~period of its goodwill and the carrying value of the goodwill. Penelec's annual review was completed in the third quarter of 2003, with no impairment indicated. The forecasts used in Penelec's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on Penelec's future evaluations of goodwill. In the first quarter of 2004, Penelec reduced goodwill by $4 million for interest received on a pre-merger income tax refund. As of March 31, 2004, Penelec had $894 million of goodwill. New Accounting Standards and Interpretations FSP 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" Issued January 12, 2004, FSP 106-1 permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Medicare Act.delay, FirstEnergy elected to defer the effects of the Medicare Act due to the lack of specific guidance. Pursuant to FSP 106-1, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 as a result of a February 2, 2004 plan amendment that required remeasurement of the plan's obligations. See Note 2 for a discussion of the effect of the federal subsidy and plan amendment on the consolidated financial statements. FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" In December 2003, the FASB issued a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", referred to as FIN 46R, which requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, Penelec adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. Adoption of FIN 46R did not have a material impact on Penelec's financial statements for the quarter ended March 31, 2004. See Note 2 for a discussion of Variable Interest Entities. 140 For the quarter ended March 31, 2004, Penelec evaluated, among other entities, its power purchase agreements and determined that it is possible that two NUG entities might be considered variable interest entities. Penelec has requested but not received the information necessary to determine whether these entities are VIEs or whether Penelec is the primary beneficiary. In most cases, the requested information was deemed to be competitive and proprietary data. As such, Penelec applied the scope exception that exempts enterprises unable to obtain the necessary informationwill continue 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. The cost of purchased power from these entities was $7 million in each of the quarters ended March 31, 2004 and 2003. Penelec isits investments as required to continue to make exhaustive efforts to obtain the necessary information in future periods and is unable to determine the possible impact of consolidating any such entity without this information. 141 by existing authoritative guidance.

125

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ~~- -------------------------------------------------------------------~~

See ~~"Management's~~“Management’s Discussion and Analysis of Results of Operation and Financial Condition - Market Risk ~~Information"~~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 this report. Based on that evaluation, those officers have concluded that the registrant's disclosure controls and procedures are effective and were designed to bring to their attention material information relating to the registrant and its consolidated subsidiaries by others within those entities.

(b)CHANGES IN INTERNAL CONTROLS

During the quarter ended March 31, ~~2004,~~2005, there were no changes in the registrants' internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting. ~~142~~

126

PART II. OTHER INFORMATION ~~- ---------------------------~~

ITEM 1.LEGAL PROCEEDINGS

Information required for Part II, Item ~~1. Legal Proceedings ----------------- Reference~~1 is ~~made~~incorporated by reference to ~~Note 3, Commitments, Guarantees~~the discussions in Notes 12 and ~~Contingencies,~~13 of the ~~Notes to~~ Consolidated Financial Statements ~~contained~~ 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

January 1-31, 2005		62,712	$	39.23		--		--
February 1-28, 2005		104,824	$	40.78		--		--
March 1-31, 2005		942,459	$	41.59		--		--

First Quarter 2005		1,109,995	$	41.38		--		--

(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 ~~a description~~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 ~~certain legal proceedings. Item~~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 6.EXHIBITS

(a)Exhibits and Reports on Form 8-K -------------------------------- (a) Exhibits Exhibit Number ------ Met-Ed ------ 12 Fixed charge ratios 31.1 Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(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 accountants 31.1 Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 32.1 Certification of chief executive officer and chie financial officer, pursuant to 18 U.S.C. Section 1350. JCP&L ----- 12 Fixed charge ratios 31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 31.3 Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 32.2 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. FirstEnergy ----------- 10-40 Employment, severance and change in control agreement between FirstEnergy Corp. and A. J. Alexander, dated February 17, 2004. 15 Letter from independent accountants 31.1 Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 32.1 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. OE and Penn ----------- 15 Letter from independent accountants 31.1 Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 32.1 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. CEI and TE ---------- 31.1 Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 32.1 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

Exhibit
Number

Met-Ed

	12	Fixed charge ratios
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

Penelec

	10.1	Term Loan Agreement, dated as of March 15, 2005, among Pennsylvania Electric Company, Union Bank of California, N.A., as Administrative Agent, Lead Arranger and Lender, and National City Bank as Arranger, Syndication Agent and Lender. (March 18, 2005 Form 8-K, Exhibit 10.1).
	12	Fixed charge ratios
	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

JCP&L

	12	Fixed charge ratios
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	31.3	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	32.2	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

127


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-(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

OE and Penn

	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

CEI

	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

TE

	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(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. ~~143~~

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. (b) Reports on Form 8-K FirstEnergy, CEI and TE ----------------------- FirstEnergy, CEI and TE each filed the following four reports on Form 8-K since December 31, 2003: A report dated January 13, 2004 reported FirstEnergy Chief Executive Officer H. Peter Burg passed away. A report dated January 20, 2004 reported Anthony J. Alexander elected as FirstEnergy Chief Executive Officer and George M. Smart elected as FirstEnergy Chairman of the Board of Directors. A report dated February 9, 2004 reported Moody's lowered debt ratings for FirstEnergy and subsidiaries. A report dated March 8, 2004 reported that FirstEnergy began Davis-Besse restart with NRC authorization. OE, Penn, JCP&L, Met-Ed and Penelec ----------------------------------- OE, Penn, JCP&L, Met-Ed and Penelec each filed the following three reports on Form 8-K since December 31, 2003: A report dated January 13, 2004 reported FirstEnergy Chief Executive Officer H. Peter Burg passed away. A report dated January 20, 2004 reported Anthony J. Alexander elected as FirstEnergy Chief Executive Officer and George M. Smart elected as FirstEnergy Chairman of the Board of Directors. A report dated February 9, 2004 reported Moody's lowered debt ratings for FirstEnergy and subsidiaries. 144

128

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.

May 10, 2004 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 145

	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