FirstEnergy - 10-Q quarterly report FY

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

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

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2005

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

SECURITIES EXCHANGE ACT OF 1934

For the transition period from

Commission	Registrant; State of Incorporation;	I.R.S. Employer
File Number	Address; and Telephone Number	Identification No.

333-21011	FIRSTENERGY CORP.	34-1843785
	(An Ohio Corporation)
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-2578	OHIO EDISON COMPANY	34-0437786
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-2323	THE CLEVELAND ELECTRIC ILLUMINATING COMPANY	34-0150020
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3583	THE TOLEDO EDISON COMPANY	34-4375005
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3491	PENNSYLVANIA POWER COMPANY	25-0718810
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3141	JERSEY CENTRAL POWER & LIGHT COMPANY	21-0485010
	(A New Jersey Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-446	METROPOLITAN EDISON COMPANY	23-0870160
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3522	PENNSYLVANIA ELECTRIC COMPANY	25-0718085
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

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

Yes XNo

Indicate by check mark whether each registrant is an accelerated filer (as defined in Rule 12b-2 of the Act):

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

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

	OUTSTANDING
CLASS	AS OF 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 outcomes (including revocation of necessary licenses or operating permits, fines or other enforcement actions and remedies) of government investigations and oversight, including by the Securities and Exchange Commission, the United States Attorney’s Office and the Nuclear Regulatory Commission as disclosed in the registrants’ Securities and Exchange Commission filings, generally, and with respect to the Davis-Besse Nuclear Power Station outage and heightened scrutiny at the Perry Nuclear Power Plant in particular, the availability and cost of capital, the continuing availability and operation of generating units, the inability to accomplish or realize anticipated benefits of strategic goals, the ability to improve electric commodity margins and to experience growth in the distribution business, the ability to access the public securities and other capital markets, further investigation into the causes of the August 14, 2003 regional power outages and the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the outages, the final outcome in the proceeding related to FirstEnergy's Application for a Rate Stabilization Plan in Ohio, the risks and other factors discussed from time to time in the registrants' Securities and Exchange Commission filings, including their annual report on Form 10-K for the year ended December 31, 2004, and other similar factors. The registrants expressly disclaim any current intention to update any forward-looking statements contained in this document as a result of new information, future events, or otherwise.

TABLE OF CONTENTS

		Pages
Glossary of Terms		iii-iv

Part I. Financial Information

Items 1. and 2. - Financial Statements and Management’s Discussion and Analysis of
Results of Operation and Financial Condition

	Notes to Consolidated Financial Statements	1-18

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

TABLE OF CONTENTS (Cont'd)

		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 current and former subsidiaries:

ATSI	American Transmission Systems, Inc., owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
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:

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 Same Counterparty”
EITF 99-19	EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent”
EPA	Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
FIN 46R	FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities"
FIN 47	FASB Interpretation 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”
FMB	First Mortgage Bonds
FSP	FASB Staff Position
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 Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004”
GAAP	Accounting Principles Generally Accepted in the United States
HVAC	Heating, Ventilation and Air-conditioning
KWH	Kilowatt-hours
LOC	Letter of Credit
MISO	Midwest Independent Transmission System Operator, Inc.
MSG	Market Support Generation
MTC	Market Transition Charge
MW	Megawatts
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Council
NJBPU	New Jersey Board of Public Utilities
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. - ORGANIZATION AND BASIS OF PRESENTATION:

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

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

These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 2004 for FirstEnergy and the Companies. The consolidated unaudited financial statements of FirstEnergy and each of the Companies reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain businesses divested in the first 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 the current year business segment organizations and operations.

FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. 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 under the equity method. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheet and the percentage share of the entity’s earnings is reported in the Consolidated Statement of Income.

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

2. - ACCOUNTING FOR CERTAIN WHOLESALE ENERGY TRANSACTIONS

FES engages in purchase and sale transactions in the PJM Market to support the supply of end-use customers, including 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 of ownership transferred with each transaction. FES has accounted for these transactions on a gross basis in accordance with EITF 99-19.

The FASB's Emerging Issues Task Force is currently considering EITF 04-13, which relates to the accounting for purchases and sales of inventory with the same counterparty. The EITF is expected to address under what circumstances two or more transactions with the same counterparty should be viewed as a single nonmonetary transaction within the scope of APB 29. If the EITF were to determine that transactions such as FES' purchases and sales in the PJM Market should be accounted for as nonmonetary transactions, FES would report the transactions prior to January 1, 2005 on a net basis. This requirement would have no impact on net income, but would reduce both wholesale revenue and purchased power expense by $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, 2005 and 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 an aggregate 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 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 consolidated financial statements are PNBV and Shippingport, two VIEs created in 1996 and 1997, respectively, to refinance debt originally issued in connection with sale and leaseback transactions. PNBV and Shippingport financial data are included in the consolidated financial statements of OE and CEI, respectively.

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

OE, CEI and TE are exposed to losses under the applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. OE, CEI and TE each have a maximum exposure to loss under these provisions of approximately $1 billion, which represents the net amount of casualty value payments upon the occurrence of specified casualty events that render the applicable plant worthless. Under the applicable sale and leaseback agreements, OE, CEI and TE have net minimum discounted lease payments of $688 million, $99 million and $566 million, respectively, that would not be payable if the casualty value payments are made.

Power Purchase Agreements

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

FirstEnergy has determined that for all but nine of these entities, neither JCP&L, Met-Ed nor Penelec have variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of FIN 46R. JCP&L, Met-Ed or Penelec may hold variable interests in the remaining nine entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants.

As required by FIN 46R, FirstEnergy periodically requests from these nine entities the information necessary to determine whether they are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. FirstEnergy has been unable to obtain the requested information, which in most cases was deemed by the requested entity to be proprietary. As such, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R. The maximum exposure to loss from these entities results from increases in the variable pricing component under the contract terms and cannot be determined without the requested data. Purchased power costs from these entities during the first quarters of 2005 and 2004 are shown in the table 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 results of JCP&L Transition, a wholly owned limited liability company of JCP&L. In June 2002, JCP&L Transition sold $320 million of transition bonds to securitize the recovery of JCP&L's bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station.

JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. The transition bonds are obligations of JCP&L Transition only and are collateralized solely by the equity and assets of JCP&L Transition, which consist primarily of bondable transition property. The bondable transition property is solely the property of JCP&L Transition.

Bondable transition property represents the irrevocable right under New Jersey law of a utility company to charge, collect and receive from its customers, through a non-bypassable TBC, the principal amount and interest on the transition bonds and other fees and expenses associated with their issuance. JCP&L sold the bondable transition property to JCP&L Transition and, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to a servicing agreement with JCP&L Transition. JCP&L is entitled to a quarterly servicing fee of $100,000 that is payable from TBC collections.

12. - COMMITMENTS, GUARANTEES AND CONTINGENCIES:

(A) GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. Such agreements include contract guarantees, surety bonds and ratings contingent collateralization provisions. As of March 31, 2005, outstanding guarantees and other assurances aggregated approximately $2.4 billion and included contract guarantees ($1.0 billion), surety bonds ($0.3 billion) and LOC ($1.1 billion).

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities - principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.9 billion (included in the $1.0 billion discussed above) as of March 31, 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 contracts.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating-downgrade or “material adverse event” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. The following table summarizes collateral provisions in effect as of March 31, 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 $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 guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has also provided an LOC (currently at $47 million), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.

(B) ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. The effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position. These environmental regulations affect FirstEnergy's earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, FirstEnergy believes it is in compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $430 million for 2005 through 2007.

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

Clean Air Act Compliance

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

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

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR will require additional reductions of NO_x and SO₂ emissions in two phases (Phase I in 2009 for NOx, 2010 for SO₂ and Phase II in 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 emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO₂ emissions in affected states to just 2.5 million tons annually. NO_x emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NO_x cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which the Companies operate affected facilities.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized a cap-and-trade program to reduce mercury emissions in two phases from coal-fired power plants. Initially, mercury emissions will decline by 2010 as a "co-benefit" from implementation of SO₂ and NO_xemission caps under the EPA's CAIR program. Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. The future cost of compliance with these regulations may be substantial.

W. H. Sammis Plant

In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities covering 44 power plants, including the W. H. Sammis Plant, which is owned by OE and Penn. In addition, the U.S. Department of Justice (DOJ) filed eight civil complaints against various investor-owned utilities, 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 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 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 United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic greenhouse gas intensity - the ratio of emissions to economic output - by 18 percent through 2012.

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

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.

Clean Water Act

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

On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system and entrainment, which occurs when aquatic species are drawn into a facility's cooling water system. The Companies are conducting comprehensive demonstration studies, due in 2008, to determine the operational measures, equipment or restoration activities, if any, necessary for compliance by their facilities with the performance standards. FirstEnergy is unable to predict the outcome of such studies. Depending on the outcome of such studies, the future cost of compliance with these standards may require material capital expenditures.

Regulation of Hazardous Waste

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

The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of March 31, 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 (JCP&L - $46.8 million, CEI - $2.3 million, TE - $0.2 million, Met-Ed - $48,000 and other - $15.2 million) as of March 31, 2005.

(C) OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation

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

In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate 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.

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 Nuclear Power Station. On December 10, 2004, FirstEnergy received a letter from the United States Attorney's Office stating that FENOC is a target of the federal grand jury investigation into alleged false statements made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. On February 10, 2005, FENOC received an additional subpoena for documents related to root cause reports regarding reactor head degradation and the assessment of reactor head management issues at Davis-Besse.

On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head described above. 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 first quarter of 2005.

If it were ultimately determined that FirstEnergy or its subsidiaries has legal liability based on the Davis-Besse head degradation, 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, which is owned and/or leased by OE, CEI, TE and 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 or its subsidiaries' financial condition.

Other Legal Matters

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

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a 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 otherwise made subject to liability based on the above matter, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.

13. - REGULATORY MATTERS:

Reliability Initiatives

In late 2003 and early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task Force) regarding enhancements to regional reliability. In 2004, FirstEnergy completed implementation of all actions and initiatives related to enhancing area reliability, improving voltage and reactive management, operator readiness and training and emergency response preparedness recommended for completion in 2004. On July 14, 2004, NERC independently verified that FirstEnergy had implemented the various initiatives to be completed by June 30 or summer 2004, with minor exceptions noted by FirstEnergy, which exceptions are now essentially complete. FirstEnergy is proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades, to existing equipment. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review the FirstEnergy filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

As a result of outages experienced in JCP&L's service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L's service reliability. On March 29, 2004, the NJBPU adopted a Memorandum of Understanding (MOU) that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L's ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a stipulation that incorporates the final report of a Special Reliability Master who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The stipulation also incorporates the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L's Planning and Operations and Maintenance programs and practices (Focused Audit). A final order in the Focused Audit docket was issued by the NJBPU on July 23, 2004. On February 11, 2005, JCP&L met with the Ratepayer Advocate to discuss reliability improvements. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.

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

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

Ohio

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

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

New Jersey

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and MTC rates. As of March 31, 2005, the accumulated deferred cost balance totaled approximately $472 million. New Jersey law allows for securitization of JCP&L's deferred balance upon application by JCP&L and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. On February 14, 2003, JCP&L filed for approval of the securitization of the deferred balance. There can be no assurance as to the extent, if any, that the NJBPU will permit such securitization.

The July 2003 NJBPU decision on JCP&L's 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 and order issued in May 2004 resulted in JCP&L recording a $5.4 million 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. The decision ordered a Phase II proceeding 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. JCP&L filed an 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 the following issues: (1) deferred cost disallowances; (2) the capital structure including the rate of return; (3) merger savings, including amortization of costs to achieve merger savings; and (4) decommissioning costs. Management is unable to predict when a decision may be reached by the NJBPU.

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.

JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balance with the exception of 300 MW from JCP&L's NUG committed supply currently being used to serve BGS customers pursuant to NJBPU order. New BGS tariffs reflecting the results of a February 2004 auction for the BGS supply became effective June 1, 2004. The auction for the supply period beginning June 1, 2005 was completed in February 2005. The NJBPU decision on the BGS 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 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The Ratepayer Advocate filed comments on February 28, 2005. On March 18, 2005, JCP&L filed a response to those comments. A schedule for further proceedings has not yet been set.

Pennsylvania

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

In accordance with PPUC directives, Met-Ed and Penelec have been negotiating with interested parties in an attempt to resolve the merger savings issues that are the subject of remand from the Commonwealth Court. These companies' combined portion of total merger savings is estimated to be 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 their October 8, 2003 petition, the PPUC approved June 30, 2004 as the date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC denied the accounting request regarding the CTC rate/shopping credit swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. Met-Ed and Penelec subsequently filed with the Commonwealth Court, on October 31, 2003, an Application for Clarification with the judge, a Petition for Review of the PPUC's October 2 and October 16 Orders, and an application for reargument if the judge, in his clarification order, indicates that Met-Ed's and Penelec's Objection was intended to be denied on the merits. The Reargument Brief before the Commonwealth Court was filed January 28, 2005.

Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sales agreement. The PLR sale is automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES retains the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR energy costs during the term of the agreement with FES. Met-Ed and Penelec are authorized to continue deferring differences between NUG contract costs and current market prices.

Transmission

On November 1, 2004, ATSI requested authority from the FERC to defer approximately $54 million of vegetation management costs ($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 for deferral of transmission-related costs beginning January 1, 2005, estimated to be approximately $8 million per month.

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

On September 16, 2004, the FERC issued an order that imposed additional obligations on CEI under certain pre-Open Access transmission contracts among CEI and the cities of Cleveland and Painesville, Ohio. Under the FERC's 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, 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 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

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 clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective no later than the end of fiscal years ending after December 15, 2005. FirstEnergy is currently evaluating the effect 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 FASB issued this Statement amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this statement are effective for nonmonetary exchanges occurring in fiscal periods beginning after June 15, 2005 and are to be applied prospectively. FirstEnergy is currently evaluating this standard but does not expect it to have a material impact on its financial statements.

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

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

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

In November 2004, the FASB issued this statement to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be “so abnormal”that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by FirstEnergy after June 30, 2005. FirstEnergy is currently evaluating this standard but does not expect it to have a material impact on the financial statements.

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

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

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

Issued in December 2004, FSP 109-1 provides guidance related to the provision within the American Jobs Creation Act of 2004 (Act) that provides a tax deduction on qualified production activities. The Act includes a tax deduction of up to 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 has three reportable segments: regulated services, power supply management services (referred to as competitive electric energy services in previous filings) and facilities (HVAC) services. The aggregate “Other”segments do not individually meet the criteria to be considered a reportable segment. FirstEnergy's primary segment is its regulated services segment, whose operations include the regulated sale of electricity and distribution and transmission services by its eight EUOC in Ohio, Pennsylvania and New Jersey. The power supply management services segment primarily consists of the subsidiaries (FES, FGCO and FENOC) that sell electricity in deregulated markets and operate the generation facilities of OE, CEI, TE and Penn resulting from the deregulation of the Companies' electric generation business. “Other”consists of MYR (a construction service company); natural gas operations (recently sold - see Note 6) and telecommunications services. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable segments.”

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

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

Segment reporting for interim periods in 2004 was reclassified to conform with the current year business segment organization and operations emphasizing FirstEnergy's regulated electric businesses and power supply management operations and the reclassification of discontinued operations (see Note 6). 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 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, 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 part of these statements.

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 integral part 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 of these 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 of these statements.

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of FirstEnergy Corp.:

We have reviewed the accompanying consolidated balance sheet of FirstEnergy Corp. and its subsidiaries as of 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.

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

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

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 3, 2005

FIRSTENERGY CORP.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

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 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 operates primarily through two core business segments.

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

Other operating segments provide a wide range of services, including heating, ventilation, air-conditioning, refrigeration, process piping, plumbing, electrical and facility control systems, high-efficiency electrotechnologies and telecommunication services. FirstEnergy continues to divest these non-core businesses. See Note 6 to the consolidated financial statements.

RESULTS OF OPERATIONS

The financial results discussed below include revenues and expenses from transactions among our business segments. A reconciliation of segment financial results is provided in Note 15 to the consolidated financial statements. The FSG business segment is included in "Other and Reconciling Adjustments" in this discussion due to its immaterial impact on current period financial results, but is presented separately in segment information provided in Note 15 to the 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 expenses.

Net income in the first quarter of 2005 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 from operations. In the first quarter of 2004, net income included $1 million from discontinued operations.

A decrease in wholesale electric revenues and purchased power costs in the first quarter of 2005 from the same period last year resulted from FES recording PJM sales and purchased power transactions on an hourly net position basis beginning in the first quarter of 2005 compared with recording each discrete transaction (on a gross basis) in the same period of 2004. This change had no impact on earnings and 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 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 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^stQuarter 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^stQuarter 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^stQuarter 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. An improvement in the gross generation margin was more than offset by higher non-fuel nuclear costs, resulting in the increased net loss.

Generation Margin -

The gross generation margin in the first quarter of 2005 improved by $12 million compared to the same period of 2004, as shown in 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 $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 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 2005 compared to the same quarter of 2004. The improvement reflected the effect of discontinued operations, which included an after-tax net gain of $17 million from discontinued operations (see Note 6). The following table summarizes the sources of income 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 voluntary contribution and an increase in the market value of pension plan assets during 2004. Combined with amendments to FirstEnergy’s health care plan in the first quarter of 2004, employee benefit expenses decreased by $20 million in the first quarter of 2005 compared to the same period in 2004. The following table summarizes the net pension and OPEB expense (excluding amounts capitalized) for the three months ended March 31, 2005 and 2004.

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

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

⁽¹⁾ Excludes the capitalized portion of postretirement benefits

costs (see Note 10 for total costs).

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

CAPITAL RESOURCES AND LIQUIDITY

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

Changes in Cash Position

The primary source of ongoing cash for FirstEnergy, as a holding company, is cash dividends from its subsidiaries. The holding company also has access to $1.375 billion of revolving credit facilities. In the first quarter of 2005, FirstEnergy received $137 million of cash dividends from its subsidiaries and paid $135 million in cash dividends to its common shareholders. There are no material restrictions on the payment of cash dividends by FirstEnergy’s subsidiaries.

As of March 31, 2005, FirstEnergy had $81 million of cash and cash equivalents ($3 million restricted as an indemnity reserve) compared with $53 million as of December 31, 2004. The major sources for changes in these balances are summarized below.

Cash Flows From Operating Activities

FirstEnergy's consolidated net cash from operating activities is provided primarily by its regulated and power supply businesses (see “RESULTS OF OPERATIONS” above). Net cash provided from operating activities was $569 million in the first quarter of 2005 and $648 million in the first quarter of 2004, summarized as follows:

	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 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 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)	$	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 decrease in cash earnings is described under "RESULTS OF OPERATIONS". The working capital increase primarily resulted from changes of $238 million in payables partially offset by a change of $182 million in receivables.

Cash Flows From Financing Activities

In the first quarters of 2005 and 2004, net cash used for financing activities of $359 million and $240 million, respectively, primarily reflected the redemptions of debt and 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 $310 million of short-term indebtedness as of March 31, 2005 compared to approximately $170 million as of December 31, 2004. Available bank borrowing capability as of March 31, 2005 included the following:

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, 2005, the Ohio Companies and Penn had the aggregate capability to issue approximately $4.3 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE and CEI are also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE and CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $650 million and $565 million, respectively, as of March 31, 2005. Under the provisions of its senior note indenture, JCP&L may issue additional FMB only as collateral for senior notes. As of March 31, 2005, JCP&L had the capability to issue $578 million of additional senior notes upon the basis of FMB collateral. Based upon applicable earnings coverage tests in their respective charters, OE, Penn, TE and JCP&L could issue a total of $4.0 billion of preferred stock (assuming no additional debt was issued) as of March 31, 2005. CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred stock.

As of March 31, 2005, approximately $1.0 billion remained under FirstEnergy's shelf registration statement, filed with the SEC in 2003, to support future securities issues. The shelf registration provides the flexibility to issue and sell various types of securities, including common stock, debt securities, and share purchase contracts and related share purchase units.

FirstEnergy’s working capital and short-term borrowing needs are met principally with a syndicated $1 billion three-year revolving credit facility maturing in June 2007. Combined with FirstEnergy’s syndicated $375 million three-year facility maturing in October 2006, a $125 million three-year facility for OE maturing in October 2006, and a syndicated $250 million two-year facility for OE maturing in May 2005, 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 short-term working capital requirements for FirstEnergy and its subsidiaries. Total unused borrowing capability under existing facilities and accounts receivable financing facilities totaled $1.9 billion as of March 31, 2005.

Borrowings under these facilities are conditioned on maintaining compliance with certain financial covenants in the agreements. FirstEnergy and OE are each required to maintain a debt to total capitalization ratio of no more than 0.65 to 1 and a contractually defined fixed charge coverage ratio of no less than 2 to 1. As of March 31, 2005, FirstEnergy’s and OE’s fixed charge coverage ratios, as defined under the credit agreements, were 4.47 to 1 and 6.87 to 1, respectively. FirstEnergy's and OE's debt to total capitalization ratios, as defined under the credit agreements, were 0.55 to 1 and 0.40 to 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 their business, condition (financial or otherwise), results of operations, or prospects.

Neither FirstEnergy's nor OE’s primary credit facilities contain any provisions that either restrict their ability to borrow or accelerate repayment of outstanding advances as a result of any change in their credit ratings. Each primary facility does contain "pricing grids", whereby the cost of funds borrowed under the facility is related to the credit ratings of the company borrowing the funds.

FirstEnergy’s regulated companies have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy’s unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. For the regulated companies, available bank borrowings include $1.75 billion from FirstEnergy and OE’s revolving credit facilities. For the unregulated companies, available bank borrowings include only FirstEnergy’s $1.375 billion of revolving credit facilities. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first quarter of 2005 was 2.66% for the regulated companies’ money pool and 2.68% for the unregulated companies' money pool.

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 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 all 250,000 outstanding shares of 7.75% preferred stock at $100 per share, both plus accrued dividends to 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 in investing activities resulted principally from property additions. Regulated services expenditures for property additions primarily include expenditures supporting the distribution of electricity. Capital expenditures by the power supply management services segment are principally generation-related. The following table summarizes first quarter 2005 and 2004 investments by FirstEnergy’s regulated services, power supply management services and other segments:

Summary of Cash Flows	Property
Used for Investing Activities	Additions			Investments			Other			Total
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 2005 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 NUG trust contribution in 2004 and increased other investment earnings, partially offset by a $91 million increase in property additions.

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

FirstEnergy’s capital spending for the period 2005-2007 is expected to be about $3.3 billion (excluding nuclear fuel), of which $998 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to be approximately $274 million, of which approximately $53 million applies to 2005. During the same period, FirstEnergy’s nuclear fuel investments are expected to be reduced by approximately $280 million and $86 million respectively, as the nuclear fuel is consumed.

GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. Such agreements include contract guarantees, surety bonds, and LOCs. Some of the guaranteed contracts contain ratings contingent collateralization provisions.

As of March 31, 2005, the maximum potential future payments under outstanding guarantees and other assurances totaled $2.4 billion as summarized below:

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

FirstEnergy Guarantees of Subsidiaries:
Energy and Energy-Related Contracts⁽¹⁾	$	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 bonds issued with various maturities.

⁽⁴⁾

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

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

with the sale and leaseback of Beaver Valley Unit 2 by OE and $134 million pledged

in connection with the sale and leaseback of Perry Unit 1 by OE.

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

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. The following table summarizes collateral provisions in effect as of March 31, 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 surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

FirstEnergy has guaranteed the obligations of the operators of the TEBSA project up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has provided an LOC (currently at $47 million), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.

OFF-BALANCE SHEET ARRANGEMENTS

FirstEnergy has obligations that are not included on its Consolidated Balance Sheet related to the sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are 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, 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 $142 million of off-balance sheet financing as of March 31, 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 Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughout the Company.

Commodity Price Risk

FirstEnergy is exposed to market risk primarily due to fluctuating electricity, natural gas, coal, nuclear fuel 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 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 2005 is summarized in the following table:

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 $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 (see Interest Rate Swap Agreements below).

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

Derivatives are included on the Consolidated Balance Sheet as of March 31, 2005 as follows:

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 2005.

⁽²⁾ Exchange traded.

⁽³⁾ Broker quote sheets.

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

FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on both FirstEnergy's trading and nontrading derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of March 31, 2005. Based on derivative contracts held as of March 31, 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

FirstEnergy utilizes fixed-to-floating interest rate swap agreements, as part of its ongoing effort to manage the interest rate risk of its debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues - protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates and interest payment dates match those of the underlying obligations. During the first quarter of 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, 2005, the debt underlying the $1.75 billion outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 5.59%, which the swaps have effectively converted to a current weighted average variable interest rate of 4.32%.

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 $956 million and $951 million as of March 31, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $96 million reduction in fair value as of March 31, 2005.

CREDIT RISK

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

FirstEnergy maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As of March 31, 2005, the largest credit concentration was with one party, currently rated investment grade, that represented 7% of FirstEnergy's total credit risk. Within its unregulated energy subsidiaries, 99% of credit exposures, net of collateral and reserve, were with investment-grade counterparties as of March 31, 2005.

Outlook

State Regulatory Matters

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

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

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

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

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

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

·	requiring corporate separation of regulated and unregulated business activities.

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

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 of March 31, 2005 and December 31, 2004, 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, 2005 (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 costs have been fully recovered. Recovery of the new

regulatory assets will begin at that time and amortization of the regulatory assets for each accounting period

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

Reliability Initiatives

FirstEnergy is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades, to existing equipment. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy's filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

As a result of outages experienced in JCP&L's service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L's service reliability. On March 29, 2004, the NJBPU adopted a Memorandum of Understanding (MOU) that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L's ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a Stipulation that incorporates the final report of an SRM who made recommendations on appropriate courses of action necessary to ensure system-wide reliability and the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L's Planning and Operations and Maintenance programs and practices (Focused Audit). A Final Order in the Focused Audit docket was issued by the NJBPU on July 23, 2004. On February 11, 2005, JCP&L met with the Ratepayer Advocate to discuss reliability improvements. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.

See Note 13 to the consolidated financial statements for a more detailed discussion of reliability initiatives, including actions by the PPUC, that impact Met-Ed, Penelec and Penn.

Ohio

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

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

New Jersey

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.

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

Pennsylvania

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

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

Transmission

Environmental Matters

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR will require additional reductions of NO_x and SO₂ emissions in two phases (Phase I in 2009 for NO_x, 2010 for SO₂ and Phase II in 2015 for both NO_x and SO₂). The Companies’ Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to the caps on SO₂ and NO_x emissions, whereas our New Jersey fossil-fired generation facilities will be subject to a cap on NO_x emissions only. According to the EPA, SO₂ emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO₂ emissions in affected states to just 2.5 million tons annually. NO_x emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NO_x cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which the Companies operate affected facilities.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized a cap-and-trade program to reduce mercury emissions in two phases from coal-fired power plants. Initially, mercury emissions will decline by 2010 as a "co-benefit" from implementation of SO₂ and NO_x emission caps under the EPA's CAIR program. Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. The future cost of compliance with these regulations may be substantial.

W. H. Sammis Plant

Climate Change

Regulation of Hazardous Waste

See Note 12(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically, the final report concludes, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations 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.

On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head described above. 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 first quarter of 2005.

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

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 interpretation of FASB Statement No. 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 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.

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

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

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 part of 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 part of these statements.

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of Ohio Edison Company:

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

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 3, 2005

OHIO EDISON COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. The OE Companies also provide generation services to those customers electing to retain the OE Companies as their power supplier. The OE Companies provide power directly to wholesale customers under previously negotiated contracts, as well as to some alternative energy suppliers under OE’s transition plan. The OE Companies have unbundled the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Power supply requirements of the OE Companies are provided by FES -- an affiliated company.

Results of Operations

Earnings on common stock in the first quarter of 2005 decreased to $56 million from $76 million in the first quarter of 2004. The earnings decrease in 2005 primarily resulted from reduced operating revenues and other income and increased nuclear operating costs, which were partially offset by decreased depreciation, changes in amortization and deferrals of regulatory assets, lower fuel and purchased power costs, and reduced financing costs.

Operating revenues decreased by $17 million or 2.3% in the first quarter of 2005 compared with the same period in 2004. Lower revenues primarily resulted from 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 of $28 million (20.3% KWH decrease) due to reduced nuclear generation available for sale. The decreased FES sales were partially offset by 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 revenues resulted from increased sales to industrial and commercial customers of $5 million and $3 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 unit prices. The industrial KWH growth was moderated by increased customer shopping. Generation services provided to industrial customers by alternative suppliers as a percent of total industrial sales delivered in OE’s service area increased by 2.1 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 in 2004. These revenue reductions are deferred for 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 2005 from the same quarter of 2004 are summarized in the following table:

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 $11 million in the first quarter of 2005 from the first quarter of 2004. The following table presents changes from the prior year by expense category.

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 2005, compared with the same quarter of 2004, resulted from decreased nuclear generation - down 20.3%. Decreased purchased power costs reflected lower KWH purchased partially offset by higher unit costs. Higher nuclear operating costs were primarily due to the Perry nuclear plant scheduled refueling outage (including an unplanned extension) in the first quarter of 2005 and the absence of nuclear refueling outages in the same period last year. The decrease in other operating costs was primarily due to reduced labor costs and lower employee benefit 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 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 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, primarily due to the accruals of 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 - Environmental Matters).

Net Interest Charges

Net interest charges continued to trend lower, decreasing by $2 million in the first quarter of 2005 compared with the same quarter of 2004, reflecting redemptions of $15 million of outstanding debt during the first quarter of 2005.

Capital Resources and Liquidity

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

Changes in Cash Position

OE's cash and cash equivalents were approximately $1 million as of March 31, 2005 and December 31, 2004.

Cash Flows From Operating Activities

Cash provided from operating activities during the first quarter of 2005 and 2004 period were as follows:

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

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 increased $161 million in the first quarter of 2005, compared with the first quarter of 2004, due to a $207 million increase from changes in working capital partially offset by a $46 million decrease in cash earnings as described above and under "Results from Operations". The increase in working capital primarily reflects changes in receivables from associated companies of $146 million and accounts payable to associated companies of $278 million, partially offset by changes in accrued taxes of $356 million. The changes for accounts payable and accrued taxes primarily reflect a $249 million reallocation of tax liabilities between associated companies under the tax sharing agreement in 2004.

Cash Flows From Financing Activities

Net cash used for financing activities decreased to $32 million in the first quarter of 2005 from $105 million in the first quarter of 2004. The decrease primarily reflected lower debt redemptions and common stock dividend payments to FirstEnergy.

OE had approximately $694 million of cash and temporary cash investments (which include short-term notes receivable from associated companies) and $210 million of short-term indebtedness as of March 31, 2005. OE has authorization from the PUCO to incur short-term debt of up to $500 million (including bank facilities and the utility money pool described below). Penn has authorization from the SEC to incur short-term debt up to its charter limit of $49 million (including the utility money pool). In addition, Penn has a $25 million receivables financing facility. As of March 31, 2005, the facility was undrawn; it expires June 30, 2005 and is expected to be renewed.

OE and Penn had the aggregate capability to issue approximately $1.9 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE is also subject to provisions of its senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE to incur additional secured debt not otherwise permitted by a specified exception of up to $650 million as of March 31, 2005. Based upon applicable earnings coverage tests in their respective charters, OE and Penn could issue a total of $2.9 billion of preferred stock (assuming no additional debt was issued) as of March 31, 2005.

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

Borrowings under these facilities are conditioned on maintaining compliance with certain financial covenants in the agreements. OE is required to maintain a debt to total capitalization ratio of no more than 0.65 to 1 and a contractually defined fixed charge coverage ratio of no less than 2 to 1. 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 each of its facilities is also conditioned upon OE making certain representations and warranties to the lending banks prior to drawing under the facilities, including a representation that there has been no material adverse change in its business, condition (financial or otherwise), results of operations, or prospects.

None of OE’s primary credit facilities contain any provisions that either restrict its ability to borrow or accelerate repayment of outstanding advances as a result of any change in its credit ratings. Each primary facility does contain "pricing grids", whereby the cost of funds borrowed under the facility is related to OE’s credit 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. 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 2005 was 2.66%.

On April 6, 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.

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

Cash Flows From Investing Activities

Net cash used for investing activities increased to $234 million in the first quarter of 2005 from $0.4 million in the first quarter of 2004. The increase resulted primarily from a $203 million increase of loans to associated companies and a $42 million increase in property additions.

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

OE’s capital spending for the period 2005-2007 is expected to be about $667 million (excluding nuclear fuel), of which approximately $216 million 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 the nuclear fuel is consumed.

Off-Balance Sheet Arrangements

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

Equity Price Risk

Included in OE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $244 million and $248 million as of March 31, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $24 million reduction in fair value as of March 31, 2005. Changes in the fair value of these investments are recorded in OCI unless recognized as a result of a sale or recognized as regulatory assets or liabilities.

Outlook

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

Regulatory Matters

In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of OE's customers elects to obtain power from an alternative supplier, OE reduces the customer's bill with a "generation shopping credit," based on the generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. OE has continuing PLR responsibility to its franchise customers through December 31, 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 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 OE's franchise area.

OE's revised Rate Stabilization Plan extends current generation prices through 2008, ensuring adequate generation supply at stabilized prices, and continues OE's support of energy efficiency and economic development efforts. 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 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 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 OE 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, OE filed an application with the PUCO seeking tariff adjustments to recover increases of approximately $14 million in transmission and ancillary service costs beginning January 1, 2006. OE 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.

OE and Penn record as regulatory assets costs which have been authorized by the PUCO, the PPUC and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. OE’s regulatory assets as of 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 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 reflected in OE's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR will require additional reductions of NO_x and SO₂ emissions in two phases (Phase I in 2009 for NO_x, 2010 for SO₂ and Phase II in 2015 for both NO_x and SO₂). The OE Companies’ Ohio and Pennsylvania fossil-fuel generation facilities will be subject to the caps on SO₂ and NO_x emissions. According to the EPA, SO₂ emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping 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 EPA's CAIR program. Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. The future cost of compliance with these regulations may be substantial.

W. H. Sammis Plant

In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities covering 44 power plants, including the W. H. Sammis Plant, which is owned by OE and Penn. In addition, the U.S. Department of Justice (DOJ) filed eight civil complaints against various investor-owned utilities, 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 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 first quarter of 2005 include 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

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

Regulation of Hazardous 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 and its subsidiaries. The most significant are described below.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically, the final report concludes, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations 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.

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 the OE Companies have a 35.24% interest. 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 or its subsidiaries' financial condition.

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

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 interpretation of FASB Statement No. 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 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"

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 Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of The Cleveland Electric Illuminating Company:

We have reviewed the accompanying consolidated balance sheet of The Cleveland Electric Illuminating Company and its subsidiaries as of 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 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

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

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

Results of Operations

Earnings on common stock in the first quarter of 2005 decreased to $13 million from $47 million in the first quarter of 2004. This decrease resulted principally from 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 2005 from the same period in 2004. Higher revenues resulted principally from increased retail generation sales revenue of $6 million (commercial - $1 million and industrial - $5 million).

Retail generation KWH sales declined slightly and were not materially affected by customer shopping as generation services provided by alternative suppliers in CEI's service area remained relatively constant in the first quarter of 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 distribution throughput decreased by $5 million in the first quarter of 2005 compared with the corresponding quarter in 2004. The decrease was due to lower residential and industrial revenues ($3 million and $4 million, respectively) reflecting lower composite unit prices and reduced distribution deliveries in the first quarter of 2005. These impacts were partially offset by higher commercial sector sales of $2 million resulting from increased distribution deliveries partially offset by lower unit prices. Under the Ohio transition plan, CEI provides incentives to customers to encourage switching to alternative energy 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 CEI's transition plan and do not affect current period earnings.

Other operating revenues increased by $6 million in the first quarter of 2005 compared with 2004, primarily due to increased revenues from the sales of its customer receivables (see Off-Balance Sheet Arrangements).

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

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 increased by $34 million in the first quarter of 2005 from the first quarter of 2004. The following table presents changes from the prior year by expense category.

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 costs in the first quarter of 2005, compared with the first quarter of 2004, reflected higher KWH purchased, partially offset by lower unit costs. 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 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 2004 was attributable to revised estimated service life assumptions for fossil generating plants. Higher amortization of regulatory assets in 2005 as compared to 2004 was primarily due to increased amortization of transition regulatory assets. Increases in the deferral of regulatory assets in 2005 from 2004 resulted from higher shopping incentive deferrals ($1 million) and deferred interest on the shopping incentives ($5 million).

Other Income

Other income decreased by $7 million in the first quarter of 2005, compared with the first quarter of 2004, primarily due to an increase in expenses related to the sales of customer receivables and a $2 million 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 $2 million in the first quarter of 2005 from the same quarter last year, reflecting the effects of redemptions and refinancings of $281 million and $46 million, respectively, subsequent to the first quarter of 2004.

Preferred Stock Dividend Requirements

Preferred stock dividend requirements increased by $1 million in the first quarter of 2005, compared to the same period last year, due to premiums related to optional preferred stock redemptions in the first quarter of 2005.

Capital Resources and Liquidity

CEI’s cash requirements in 2005 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing net debt and preferred stock outstanding. 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, 2005, CEI had $207,000 of cash and cash equivalents, compared with $197,000 as of December 31, 2004. The major sources of changes in these balances are summarized below.

Cash Flows from Operating Activities

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

Operating Cash Flows	2005		2004
	*(In millions)*

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

⁽¹⁾Cash earnings 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 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		$	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 under "Results of Operations", partially offset by a $14 million increase from working capital and other cash flows. The largest factors contributing to the change in working capital and other cash flows were changes in accrued taxes, accrued interest and accounts payable, partially offset by changes in receivables.

Cash Flows from Financing Activities

Net cash used for financing activities increased $19 million in the first quarter of 2005 from the first quarter of 2004. The increase in funds used for financing activities resulted from $98 million of optional redemptions of preferred stock in the first quarter of 2005, partially offset by a reduction in net debt redemptions.

CEI had $207,000 of cash and temporary investments and approximately $471 million of short-term indebtedness as of March 31, 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 $1.4 billion of additional FMB on the basis of property additions and retired bonds under the terms of its mortgage indenture. The issuance of FMB by CEI is subject to a provision of its senior note indenture generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, this provision would permit CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $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 2005 was 2.66%.

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

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 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 provided from investing activities was $82 million in the first quarter of 2005 compared to cash used for investing activities of $7 million in the first quarter of 2004. The change was primarily due to increased loan payments received from associated companies, partially offset by higher property additions.

During the remaining three quarters of 2005, capital requirements for property additions are expected to be about $85 million, including $1 million for nuclear fuel. CEI has additional requirements of approximately $1 million to meet sinking fund requirements for preferred stock during the remainder of 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 Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant. As of March 31, 2005, the present value of these operating lease commitments, net of trust investments, total $99 million.

CEI sells substantially all of its retail customer receivables to CFC, its wholly owned 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 $94 million of off-balance sheet financing as of March 31, 2005.

Equity Price Risk

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

Outlook

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

Regulatory Matters

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. FES acts as an alternate supplier for a portion of the load in CEI's franchise area.

CEI's revised Rate Stabilization Plan extends current generation prices through 2008, ensuring adequate generation supply at stabilized prices, and continues CEI's support of energy efficiency and economic development efforts. 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 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 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 CEI 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, 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 been charged to income when incurred. CEI's regulatory assets as of March 31, 2005 and December 2004 were $0.9 billion and $1.0 billion, respectively. CEI is deferring customer shopping incentives and interest costs as new regulatory assets in accordance with its transition and rate stabilization plans. These regulatory assets total $320 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 new regulatory assets will begin at that time and amortization of the regulatory assets for each accounting period will be equal to the surcharge revenue recognized during that period.

See Note 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 period that they are both probable and reasonably estimable.

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR will require additional reductions of NO_x and SO₂ emissions in two phases (Phase I in 2009 for NO_x, 2010 for SO₂ and Phase II in 2015 for both NO_x and SO₂). CEI's Ohio and Pennsylvania fossil-fuel generation facilities will be subject to the caps on SO₂ and NO_x emissions. According to the EPA, SO₂ emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO₂ emissions in affected states to just 2.5 million tons annually. NO_x emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NO_x cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which CEI operates affected facilities.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized a cap-and-trade program to reduce mercury emissions in two phases from coal-fired power plants. Initially, mercury emissions will decline by 2010 as a "co-benefit" from implementation of SO₂ and NO_x emission caps under the EPA's CAIR program. Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. The future cost of compliance with these regulations may be substantial.

Climate Change

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

Regulation of Hazardous Waste

CEI has been named a PRP at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of 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. Included in Current Liabilities are accrued liabilities aggregating approximately $2.3 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 CEI's normal business operations pending against CEI and its subsidiaries. The most significant not otherwise discussed above are described below.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically, the final report concludes, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations 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.

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

On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head described above. 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 proposed fine of $1.8 million during the 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, in which CEI has a 44.85% interest. 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 or its subsidiaries' financial condition.

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

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 interpretation of FASB Statement No. 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 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"

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 part of 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 integral part of these statements.

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of The Toledo Edison Company:

We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of 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 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

THE TOLEDO EDISON COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

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

Results of Operations

Earnings applicable to common stock in the first quarter of 2005 decreased to a loss of $2 million from earnings of $5 million in the first quarter of 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 2005 from the same period of 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 higher unit prices and a 1.6% KWH sales increase. The increase in commercial sector revenues was principally due to a 6.1% KWH sales increase. Residential retail generation revenues were nearly unchanged for the first quarter of 2005 as compared to last year due to higher unit prices offsetting the effect of a 4.5% KWH sales decrease. The increased commercial volume sales partially reflected the effect of lower customer shopping. Generation services provided to commercial customers by alternative suppliers as a percent of total commercial sales 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 FES.

Revenues from distribution throughput decreased by $7 million in the first quarter of 2005 from the corresponding quarter of 2004. The decrease was due to lower industrial and residential revenues ($7 million and $1 million), principally due to lower composite 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 TE’s transition plan and do not affect current period earnings (see Regulatory Matters below).

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

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 increased by $12 million in the first quarter of 2005 from the same quarter of 2004. The following table presents changes from the prior year by expense category.

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 three months of 2005, compared with the same period of 2004, resulted principally from increased fossil and nuclear generation — up 28.1% and 29.8%, respectively. Lower purchased power costs reflect lower KWH purchased, partially offset by increased unit costs. Increased nuclear operating costs in the first quarter of 2005 compared to the first quarter of 2004 were 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 2005 and no scheduled outages in the first quarter of 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 resulted from higher shopping incentives ($0.5 million) and deferred interest on the shopping incentives ($1.5 million).

Other Income

Other income decreased by $3 million in the first quarter of 2005, compared to the same period of 2004, due to a decrease in interest income earned on nuclear decommissioning trust investments and the accrual of a $1.6 million proposed 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 $1 million in the first three months of 2005 from the same period of 2004, reflecting redemptions and refinancing subsequent to the end of the first quarter of 2004.

Capital Resources and Liquidity

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

Changes in Cash Position

There was no change as of March 31, 2005 from December 31, 2004 in TE's cash and cash equivalents of $15,000.

Cash Flows From Operating Activities

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

	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 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 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)	$	--		$	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 by $17 million in the first quarter of 2005 from the first quarter of 2004 as a result of a $35 million increase in working capital partially offset by a $18 million decrease in cash earnings described above and under "Results of Operations". The change in working capital was primarily due to changes in receivables and accounts payable.

Cash Flows From Financing Activities

Net cash used for financing activities decreased by $306,000 in the first quarter of 2005, as compared to the same period of 2004, reflecting a change in net debt redemptions.

TE had $137 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $395 million of short-term indebtedness as of March 31, 2005. TE has authorization from the PUCO to incur short-term debt of up to $500 million (including the utility money pool described below). As of 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 indenture. Based upon applicable earnings coverage 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, 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%.

TE’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 on all securities is stable.

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 FMB.

Cash Flows From Investing Activities

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

TE’s capital spending for the last three quarters of 2005 is expected to be about $46 million (excluding $1 million for nuclear fuel). These cash requirements are expected to be satisfied from internal cash and short-term borrowings.

TE’s capital spending for the period 2005-2007 is expected to be about $192 million (excluding nuclear fuel) of which approximately $56 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to total approximately $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 Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley Unit 2. As of March 31, 2005, the present value of these operating lease commitments, net of trust investments, 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 special purpose entity” under SFAS 140) under an asset-backed securitization agreement. This arrangement provided $48 million of off-balance sheet financing as of March 31, 2005.

Equity Price Risk

Included in TE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $194 million and $188 as of March 31, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $19 million reduction in fair value as of March 31, 2005. Changes in 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 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.

TE records as regulatory assets costs which have been authorized by the PUCO and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. TE's regulatory assets as of March 31, 2005 and December 2004 were $349 million and $375 million, respectively. TE is deferring customer shopping incentives and interest costs as new regulatory assets in accordance with its transition and rate stabilization plans. These regulatory assets total $98 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 new regulatory assets will begin at that time and amortization of the regulatory assets for each accounting period will be equal to the surcharge revenue recognized during that period.

See Note 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 period that they are both probable and reasonably estimable.

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR will require additional reductions of NO_x and SO₂ emissions in two phases (Phase I in 2009 for NO_x, 2010 for SO₂ and Phase II in 2015 for both NO_x and SO₂). TE's Ohio and Pennsylvania fossil-fuel generation facilities will be subject to the caps on SO₂ and NO_x emissions. According to the EPA, SO₂ emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO₂ emissions in affected states to just 2.5 million tons annually. NO_x emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NO_x cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which TE operates affected facilities.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized a cap-and-trade program to reduce mercury emissions in two phases from coal-fired power plants. Initially, mercury emissions will decline by 2010 as a "co-benefit" from implementation of SO₂ and NO_x emission caps under the EPA's CAIR program. Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. The future cost of compliance with these regulations may be substantial.

Climate Change

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

Regulation of Hazardous Waste

TE has been named a PRP at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of 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. Included in Current Liabilities are accrued liabilities aggregating approximately $0.2 million as of March 31, 2005. TE accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably determine the amount of such costs. Unasserted claims are reflected in TE's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

See Note 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 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.

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

On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head described above. 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 proposed fine of $1.6 million during the first quarter of 2005.

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

On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the past two years. FENOC operates the Perry Nuclear Power Plant, in which TE has a 19.91% interest. 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 or its subsidiaries' financial condition.

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

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 interpretation of FASB Statement No. 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 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"

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 part of 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 integral part of these statements.

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of Pennsylvania Power Company:

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

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 3, 2005

PENNSYLVANIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

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

Results of Operations

Earnings on common stock in the first quarter of 2005 decreased to $14 million from $19 million in the first quarter of 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 2005 as compared with the first quarter of 2004. The lower revenues primarily resulted from a $9 million decrease in wholesale sales to FES due to less nuclear generation available for sale. Higher retail generation sales revenues 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 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 result of the annual CTC reconciliation.

Changes in electric generation and distribution deliveries in the first quarter of 2005 from the same quarter in 2004 are summarized in the following table:

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 $4 million in the first quarter of 2005 from the first quarter of 2004. Lower fuel costs in the first quarter of 2005, compared with the same quarter of 2004, resulted from reduced nuclear generation. Lower purchased power costs in the first three months of 2005 reflected decreased KWH purchases and higher unit costs. Nuclear operating costs increased due to the Perry scheduled refueling outage (including an unplanned extension) in the first quarter of 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 $851,000 in the first quarter of 2005 from the same period last year, reflecting redemptions of $22 million total principal amount of debt securities since the first quarter of 2004.

Capital Resources and Liquidity

Penn’s cash requirements in 2005 and thereafterfor operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met with a combination of cash from operations and funds from the capital markets. Available borrowing capacity under credit facilities will be used to manage working capital requirements.

Changes in Cash Position

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

Cash Flows From Operating Activities

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

	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 From Financing Activities

Net cash used for financing activities totaled $10 million in the first quarter of 2005, compared with $22 million in the first quarter of 2004. This decrease resulted from reduced debt redemptions in the first quarter of 2005, compared with the corresponding 2004 period.

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

Penn has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries, 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 under these arrangements in the first quarter of 2005 was 2.66%.

In addition, Penn has a $25 million receivables financing facility through its subsidiary. As of March 31, 2005, the facility was undrawn; it expires June 30, 2005 and is expected to be renewed.

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

Cash Flows From Investing Activities

Net cash used in investing activities totaled $28 million in the first quarter of 2005, compared with $13 million in the same quarter of 2004. The $15 million increase in the 2005 period reflects an increase in property additions.

During the remaining three quarters of 2005, capital requirements for property additions are expected to be about $67 million, including $9 million for nuclear fuel. Penn has additional requirements of approximately $2 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2005. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements.

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

Outlook

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

Regulatory Matters

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 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 Penn’s rates is excluded from their bill and the 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 entitled to recover $236 million of stranded costs through the CTC that began in 1999 and ends in 2006.

Regulatory assets and liabilities are costs which have been authorized by the PPUC and the FERC for recovery from or credit to customers in future periods and, without such authorization, would have been charged or credited to income when incurred. Penn's net regulatory liabilities were approximately $27 million and $18 million as of March 31, 2005 and December 31, 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

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

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR will require additional reductions of NO_x and SO₂emissions in two phases (Phase I in 2009 for NO_x, 2010 for SO₂ and Phase II in 2015 for both NO_x and SO₂). Penn's Ohio and Pennsylvania fossil-fuel generation facilities will be subject to the caps on SO₂ and NO_xemissions. According to the EPA, SO₂ emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO₂ emissions in affected states to just 2.5 million tons annually. NO_x emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NO_x cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which Penn operates affected facilities.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized a cap-and-trade program to reduce mercury emissions in two phases from coal-fired power plants. Initially, mercury emissions will decline by 2010 as a "co-benefit" from implementation of SO₂ and NO_x emission caps under the EPA's CAIR program. Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. The future cost of compliance with these regulations may be substantial.

W. H. Sammis Plant

In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities covering 44 power plants, including the W. H. Sammis Plant, which is owned by OE and Penn. In addition, the U.S. Department of Justice (DOJ) filed eight civil complaints against various investor-owned utilities, 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 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 (Penn's share is $0.7 million). Results for the first quarter of 2005 include the $0.7 million penalty payable by Penn and a $0.8 million liability for cash contributions toward environmentally beneficial projects.

Climate Change

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

Other Legal Proceedings

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

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically, the final report concludes, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations 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.

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 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 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 interpretation of FASB Statement No. 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 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"

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 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, 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 previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 9 to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 6 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 3, 2005

JERSEY CENTRAL POWER & LIGHT COMPANY

MANAGEMENT’S DISCUSSION AND

ANALYSIS OF RESULTS OF OPERATIONS

AND FINANCIAL CONDITION

JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts business in New Jersey, providing regulated electric transmission and distribution services. JCP&L also provides generation services to those customers electing to retain JCP&L as their power supplier. JCP&L has restructured its electric rates in unbundled service charges and transition cost recovery charges. JCP&L continues to deliver power to homes and businesses through its existing distribution system.

Results of Operations

Earnings on common stock in the 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 (residential - $14 million and commercial - $9 million) were due to 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 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.

102

As a result of outages experienced in JCP&L's service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L's service reliability. On March 29, 2004, the NJBPU adopted a Memorandum of Understanding (MOU) that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L's ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a Stipulation that incorporates the final report of an SRM who made recommendations on appropriate courses of action necessary to ensure system-wide reliability and the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L's Planning and Operations and Maintenance programs and practices (Focused Audit). A Final Order in the Focused Audit docket was issued by the NJBPU on July 23, 2004. On February 11, 2005, JCP&L met with the Ratepayer Advocate to discuss reliability improvements. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.

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.

103

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”

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 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.

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 part of 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 these balance 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 an integral 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 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 subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also provides generation service to those customers electing to retain Met-Ed as their power supplier. Met-Ed has unbundled the price for electricity into its component elements - including generation, transmission, distribution and transition charges. Met-Ed continues to deliver power to homes and businesses through its existing distribution system.

Results of Operations

Net income in the first quarter of 2005 decreased to $16 million from $18 million in the first quarter of 2004. The 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 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 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 same period of 2004. Also contributing to the higher operating revenues was a $10 million increase due to 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 KWH deliveries in the first quarter of 2005 compared to the first quarter 2004 are summarized in the following table:

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 increased by $37 million in the first quarter of 2005 from the first quarter of 2004. Purchased power costs increased in 2005 primarily due to 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 from FES. The net increase in KWH purchases was attributable to the increase in retail generation sales.

Other operating costs increased in the first quarter of 2005 primarily due to $27 million higher PJM ancillary transmission expenses, congestion charges, and FTR/ARR expenses. The transmission expense increase resulted from Met-Ed’s assumption of PLR transmission related transactions discussed above. Other operating costs also increased due to 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 2005 due to higher gross receipt taxes.

Capital Resources and Liquidity

Met-Ed’s cash requirements in 2005 and thereafter, for operating expenses, construction expenditures and scheduled debt maturities are expected to be met with a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

As of March 31, 2005 and December 31, 2004, Met-Ed had $120,000 of cash and cash equivalents.

Cash Flows From Operating Activities

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

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 From Financing Activities

Net cash provided from financing activities was $19 million in the first quarter of 2005 compared to $127 million in the first quarter of 2004. The decrease primarily reflected $29 million of short-term borrowings in the first quarter of 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 and temporary investments (which included short-term notes receivable from associated companies) and $109 million of short-term borrowings outstanding. Met-Ed has authorization from the SEC to incur short-term debt up to $250 million (including the utility money pool). Under the terms of Met-Ed’s senior note indenture, no more first mortgage bonds can be issued so long as the senior bonds are outstanding. Met-Ed had no restrictions on the issuance of preferred stock.

111

In addition, Met-Ed has an $80 million customer receivables financing facility. The facility was undrawn as of March 31, 2005; it expires June 30, 2005 and is expected to be renewed.

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 2005 was 2.66%.

Met-Ed’s access to capital markets and costs of financing are dependent on the ratings of its securities and that of FirstEnergy. The ratings outlook on all securities is stable.

Cash Flows From Investing Activities

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

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

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 which approximately $67 million applies to 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 Risk Policy Committee, comprised of members of senior management, provides general management to risk management activities throughout the Company.

Commodity Price Risk

Met-Ed is exposed to market risk primarily due to fluctuations in electricity and natural gas prices. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including options and futures contracts. The derivatives are used for hedging purposes. Most of Met-Ed's non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. As of March 31, 2005, Met-Ed’s commodity derivative contract was an embedded option with a fair value of $27 million. A decrease of $5 million in the value of this asset was recorded as a decrease in a regulatory liability and, therefore, had no impact on net income.

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, 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. The valuation of the derivative 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.

112

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, 2005.

Equity Price Risk

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

OUTLOOK

The electric industry continues to transition to a more competitive environment and all of Met-Ed's customers can select alternative energy suppliers. Met-Ed 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. 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. 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 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. Met-Ed's regulatory assets as of March 31, 2005 and December 31, 2004 were $750 million and $693 million, respectively.

Met-Ed purchases a portion of its PLR requirements from FES through a wholesale power sales agreement. The PLR sale is automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES retains the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed under its NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's exposure to high wholesale power prices by providing power at a fixed price for its uncommitted PLR energy costs during the term of the agreement with FES. Met-Ed is authorized to continue deferring differences between NUG contract costs and current market prices.

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

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, including actions by the PPUC, 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 amount of such costs. Unasserted claims are reflected in Met-Ed's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

113

Met-Ed has been named a PRP at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of 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. Included in Other Noncurrent Liabilities are accrued liabilities aggregating approximately $48,000 as of March 31, 2005.

Other Legal Proceedings

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

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically, the final report concludes, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations 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.

114

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 clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This interpretation is effective no later than the end of fiscal years ending after December 15, 2005. 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"

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 are an 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 an integral part of these statements.

118

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of Pennsylvania Electric Company:

We have reviewed the accompanying consolidated balance sheet of Pennsylvania Electric Company and its subsidiaries as of 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 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

119

PENNSYLVANIA ELECTRIC COMPANY

MANAGEMENT’S DISCUSSION AND

ANALYSIS OF RESULTS OF OPERATIONS

AND FINANCIAL CONDITION

Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern, western and south central Pennsylvania, providing regulated transmission and distribution services. Penelec also provides generation services to those customers electing to retain Penelec as their power supplier. Penelec has unbundled the price for electricity into its component elements - including generation, transmission, distribution and transition charges.

Results of Operations

Net income in the first quarter of 2005 increased to $21 million, compared to $6 million in the first quarter of 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 due to 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 2005 compared to the first quarter of 2004.

Capital Resources and Liquidity

Penelec’s cash requirements in 2005 and thereafter, for operating expenses, construction expenditures and scheduled debt maturities are expected to be met by a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

As of March 31, 2005, Penelec had $35,000 of cash and cash equivalents compared with $36,000 as of December 31, 2004. The major sources for changes in these balances are summarized below.

Cash Flows From Operating Activities

Net cash provided from operating activities was $24 million in the first quarter of 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 table above) are not a measure of performance calculated in accordance with GAAP. Penelec believes that cash earnings is a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance.

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 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 long-term debt financing of $150 million, a $60 million decrease in debt redemptions and $5 million of common stock dividend payments to FirstEnergy in the first quarter of 2005.

121

Penelec had approximately $10 million of cash and temporary investments (which include short-term notes receivable from associated companies) and approximately $240 million of short-term indebtedness as of March 31, 2005. Penelec has authorization from the SEC to incur short-term debt of up to $250 million (including the utility money pool). Penelec will not issue FMB other than as collateral for senior notes, since its senior note indentures prohibit (subject to certain exceptions) Penelec from issuing any debt which is senior to the senior notes. As of March 31, 2005, Penelec did not have the ability to issue additional senior notes based upon FMB collateral. Penelec has no restrictions on the issuance of preferred stock.

In addition, Penelec has a $75 million customer receivables financing facility that was drawn for $70 million as of March 31, 2005. The facility expires on 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 that of FirstEnergy. The ratings outlook on all securities is stable.

Cash Flows From Investing Activities

Cash used for investing activities was $17 million in the first quarter of 2005 compared to $62 million in the first quarter of 2004. The decrease was primarily due to the absence in 2005 of a $51 million repayment to the NUG trust fund in 2004, partially offset by increased loans of $3 million to associated companies. In both periods, cash outflows for property additions were made to support the distribution of electricity.

During the remaining quarters of 2005, capital requirements for property additions are expected to be about $73 million. Penelec has additional requirements of approximately $11 million for maturing long-term debt during the remainder of 2005. Those requirements are expected to be satisfied from internal cash and short-term credit arrangements.

Penelec’s capital spending for the period 2005-2007 is expected to be about $272 million for property additions and improvements, of which about $89 million applies to 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 Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughout the Company.

Commodity Price Risk

Penelec is exposed to market risk primarily due to fluctuations in electricity and natural gas prices. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including options and futures contracts. The derivatives are used for hedging purposes. Penelec’s non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. As of March 31, 2005, Penelec’s commodity derivatives contract was an embedded option with a fair value of $14 million. A decrease of $1 million in the value of this asset was recorded as a decrease in a regulatory liability and, therefore, had no impact on net income.

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, 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. The valuation of the derivative contract at March 31, 2005 uses prices from sources shown in the following table:

122

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.

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, 2005.

Equity Price Risk

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

Outlook

The electric industry continues to transition to a more competitive environment and all of Penelec's customers can select alternative energy suppliers. Penelec 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. 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. 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 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. Penelec's regulatory assets as of March 31, 2005 and December 31, 2004 were $278 million and $200 million, respectively.

Penelec purchases a portion of its PLR requirements from FES through a wholesale power sales agreement. The PLR sale is automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES retains the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Penelec under its NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Penelec's exposure to high wholesale power prices by providing power at a fixed price for its uncommitted PLR energy costs during the term of the agreement with FES. Penelec is authorized to continue deferring differences between NUG contract costs and current market prices.

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

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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 amount of such costs. Unasserted claims are reflected in Penelec's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

Penelec has been named a PRP at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis.

Other Legal Proceedings

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

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area.Specifically, the final report concludes, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations 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.

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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 clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This interpretation is effective no later than the end of fiscal years ending after December 15, 2005. 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"

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4. CONTROLS AND PROCEDURES

(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

The applicable registrant's chief executive officer and chief financial officer have reviewed and evaluated the registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e), as of the end of the date covered by 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, 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.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 12 and 13 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES

(e) FirstEnergy

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

							Maximum Number
							(or Approximate
					Total Number of		Dollar Value) of
					Shares Purchased		Shares that May
	Total Number				As Part of Publicly		Yet Be Purchased
	of Shares		Average Price		Announced Plans		Under the Plans
Period	Purchased (a)		Paid per Share		or Programs (b)		or Programs

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 Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the Executive and Director Incentive Compensation Plan.

(b)	FirstEnergy does not currently have any publicly announced plan or program for share purchases.

ITEM 6. EXHIBITS

(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

	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.

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.

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 5, 2005

	FIRSTENERGY CORP.
	Registrant

	OHIO EDISON COMPANY
	Registrant

	THE CLEVELAND ELECTRIC
	ILLUMINATING COMPANY
	Registrant

	THE TOLEDO EDISON COMPANY
	Registrant

	PENNSYLVANIA POWER COMPANY
	Registrant

	JERSEY CENTRAL POWER & LIGHT COMPANY
	Registrant

	METROPOLITAN EDISON COMPANY
	Registrant

	PENNSYLVANIA ELECTRIC COMPANY
	Registrant

		/s/ Harvey L. Wagner
	Harvey L. Wagner
		Vice President, Controller and Chief Accounting Officer

129

FirstEnergy - 10-Q quarterly report FY

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