THE CLEVELAND ELECTRIC

ILLUMINATING COMPANY

2004 ANNUAL REPORT TO STOCKHOLDERS

The Cleveland Electric Illuminating Company is a wholly owned electric utility operating subsidiary of FirstEnergy Corp. It engages in the generation, distribution and sale of electric energy in an area of approximately 1,700 square miles in northeastern Ohio. It also engages in the sale, purchase and interchange of electric energy with other electric companies. The area it serves has a population of approximately 1.9 million.

Contents	Page
Glossary of Terms		i-ii
Management Reports		1
Report of Independent Registered Public Accounting Firm		2
Selected Financial Data		3
Management's Discussion and Analysis		4-15
Consolidated Statements of Income		16
Consolidated Balance Sheets		17
Consolidated Statements of Capitalization		18
Consolidated Statements of Common Stockholder's Equity		19
Consolidated Statements of Preferred Stock		19
Consolidated Statements of Cash Flows		20
Consolidated Statements of Taxes		21
Notes to Consolidated Financial Statements		22-41

GLOSSARY OF TERMS

The following abbreviations and acronyms are used in this report to identify The Cleveland Electric Illuminating Company and its affiliates:

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
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
FirstEnergy	FirstEnergy Corp., a registered public utility holding company
JCP&L	Jersey Central Power & Light Company, an affiliated New Jersey electric utility
Met-Ed	Metropolitan Edison Company, an affiliated Pennsylvania electric utility
OE	Ohio Edison Company, an affiliated Ohio electric utility
Ohio Companies	CEI, OE and TE
Penelec	Pennsylvania Electric Company, an affiliated Pennsylvania electric utility
Penn	Pennsylvania Power Company, an affiliated Pennsylvania electric utility
Shippingport	Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
TE	The Toledo Edison Company, an affiliated Ohio electric utility
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 29	APB Opinion No. 29, "Accounting for Nonmonetary Transactions"
ARB	Accounting Research Bulletin
ARB 43	ARB No. 43, "Restatement and Revision of Accounting Research Bulletins"
ARO	Asset Retirement Obligation
CO2	Carbon Dioxide
CTC	Competitive Transition Charge
ECAR	East Central Area Reliability 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 03-16	EITF Issue No. 03-16, "Accounting for Investments in Limited Liability Companies"
EITF 97-4	EITF Issue No. 97-4 "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statements No. 71 and 101"
EPA	Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN 46R	FASB Interpretation No. 46 (revised December 2003), "Consolidation of Variable Interest Entities"
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"
FSP 106-1	FASB Staff Position No.106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003"
FSP 106-2	FASB Staff Position No.106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003"
FSP 109-1	FASB Staff Position No. 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"
GAAP	Accounting Principles Generally Accepted in the United States
IRS	Internal Revenue Service
KWH	Kilowatt-hours
MACT	Maximum Achievable Control Technologies
Medicare Act	Medicare Prescription Drug, Improvement and Modernization Act of 2003
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service
MW	Megawatts
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Council

i

GLOSSARY OF TERMS, Cont.

NOAC	Northwest Ohio Aggregation Coalition
NOX	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
OCC	Ohio Consumers' Counsel
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
PJM	PJM Interconnection L. L. C.
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
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 87	SFAS No. 87, "Employers' Accounting for Pensions"
SFAS 101	SFAS No. 101, "Accounting for Discontinuation of Application of SFAS 71"
SFAS 106	SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions"
SFAS 115	SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities"
SFAS 140	SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities"
SFAS 142	SFAS No. 142, "Goodwill and Other Intangible Assets"
SFAS 143	SFAS No. 143, "Accounting for Asset Retirement Obligations"
SFAS 144	SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"
SFAS 150	SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both  Liabilities and Equity"
SO2	Sulfur Dioxide
VIE	Variable Interest Entity

ii

MANAGEMENT REPORTS

Management's Responsibility for Financial Statements

The consolidated financial statements were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2004 consolidated financial statements.

FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s Board of Directors, review the results and performance of operating units within the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.

FirstEnergy’s Audit Committee consists of five independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent Registered Public Accounting Firm and is charged with reviewing and approving all services performed for the Company by the independent Registered Public Accounting Firm and for reviewing and approving the related fees. The Committee reviews the independent Registered Public Accounting Firm's report on internal quality control and reviews all relationships between the independent Registered Public Accounting Firm and the Company, in order to assess the independent Registered Public Accounting Firm's independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held six meetings in 2004.

Management's Reports on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2004. Management’s assessment of the effectiveness of the Company’s internal control over financial reporting, as of December 31, 2004, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page 2.

1

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of The Cleveland Electric Illuminating Company:

We have completed an integrated audit of The Cleveland Electric Illuminating Company’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes present fairly, in all material respects, the financial position of The Cleveland Electric Illuminating Company and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2(G) to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations as of January 1, 2003. As discussed in Note 6 to the consolidated financial statements, the Company changed its method of accounting for the consolidation of variable interest entities as of December 31, 2003.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in the accompanying Management Report on Internal Control Over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP

Cleveland, Ohio

March 7, 2005

2

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

SELECTED FINANCIAL DATA

	2004			2003			2002			2001			2000
	(Dollars in thousands)
GENERAL FINANCIAL INFORMATION:
Operating Revenues	$	1,808,485		$	1,719,739		$	1,843,671		$	2,064,622		$	1,890,339
Operating Income	$	327,909		$	255,615		$	306,152		$	354,422		$	397,568
Income Before Cumulative Effect of Accounting Change	$	236,531		$	197,033		$	136,952		$	177,905		$	210,424
Net Income	$	236,531		$	239,411		$	136,952		$	177,905		$	210,424
Earnings on Common Stock	$	229,523		$	231,885		$	121,262		$	153,067		$	189,581
Total Assets	$	6,690,465		$	6,773,448		$	6,510,243		$	6,526,596		$	6,756,921
CAPITALIZATION AS OF DECEMBER 31:
Common Stockholder’s Equity	$	1,853,561		$	1,778,827		$	1,200,001		$	1,082,041		$	1,095,874
Preferred Stock-
Not Subject to Mandatory Redemption		96,404			96,404			96,404			141,475			238,325
Subject to Mandatory Redemption		--			--			105,021			106,288			26,105
Long-Term Debt and Other Long-Term Obligations		1,970,117			1,884,643			1,975,001			2,156,322			2,634,692
Total Capitalization	$	3,920,082		$	3,759,874		$	3,376,427		$	3,486,126		$	3,994,996
CAPITALIZATION RATIOS:
Common Stockholder’s Equity		47.3	%		47.3	%		35.5	%		31.0	%		27.4	%
Preferred Stock-
Not Subject to Mandatory Redemption		2.5			2.6			2.9			4.1			6.0
Subject to Mandatory Redemption		--			--			3.1			3.0			0.6
Long-Term Debt and Other Long-Term Obligations		50.2			50.1			58.5			61.9			66.0
Total Capitalization		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%
DISTRIBUTION KWH DELIVERIES (Millions):
Residential		5,264			5,216			5,370			5,061			5,061
Commercial		4,817			4,690			4,628			4,907			6,656
Industrial		9,006			8,908			8,921			9,593			8,320
Other		162			169			167			166			167
Total		19,249			18,983			19,086			19,727			20,204
CUSTOMERS SERVED:
Residential		674,292			669,337			677,095			673,852			667,115
Commercial		81,093			80,596			71,893			70,636			69,103
Industrial		2,211			2,318			4,725			4,783			4,851
Other		293			286			289			292			307
Total		757,889			752,537			754,002			749,563			741,376
Number of Employees		905			949			974			1,025			1,046

3

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT’S DISCUSSION AND

ANALYSIS OF RESULTS OF OPERATIONS

AND FINANCIAL CONDITION

This discussion 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, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), adverse regulatory or legal decisions and outcomes (including revocation of necessary licenses or operating permits, fines or other enforcement actions and remedies) of governmental investigations and oversight, including by the Securities and Exchange Commission, the United States Attorney's Office and the Nuclear Regulatory Commission as disclosed in our Securities and Exchange Commission filings, generally, and with respect to the Davis-Besse Nuclear Power Station outage in particular, the availability and cost of capital, the continuing availability and operation of generating units, our ability to experience growth in the distribution business, our ability to access the public securities and other capital markets, further investigation into the causes of the August 14, 2003, regional power outage and the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the outage, the final outcome in the proceeding related to our Application for a Rate Stabilization Plan in Ohio, the risks and other factors discussed from time to time in our Securities and Exchange Commission filings, and other similar factors. We expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events, or otherwise.

Results of Operations

Earnings on common stock in 2004 decreased 1.0% to $230 million from $232 million in 2003. Earnings on common stock in 2003 included an after-tax gain of $42 million from the cumulative effect of an accounting change due to the adoption of SFAS 143. Income before the cumulative effect increased to $237 million in 2004 from $197 million in 2003. This increase resulted principally from higher operating revenues, lower nuclear operating costs and reduced interest charges. These factors were partially offset by higher fuel and purchased power costs, depreciation and amortization charges and the absence of a 2003 gain representing net proceeds from the settlement of our claim against NRG relating to the terminated sale of three of our fossil power plants (see Note 7). Operating revenues were higher in 2004 due to significant increases in sales to FES. Lower nuclear operating costs in 2004 compared with 2003, were due to reduced incremental maintenance costs associated with the Davis-Besse extended outage and the absence of nuclear outages at Beaver Valley Unit 2 and the Perry Plant in 2003. Lower net interest charges in 2004, compared with 2003, were primarily due to debt redemptions and refinancing activities.

Earnings on common stock in 2003 increased 91.2% to $232 million from $121 million in 2002. The increase in earnings in 2003 was due primarily to the NRG after-tax gain of $75 million and the cumulative effect of an accounting change. Excluding these gains, earnings on common stock decreased $6 million in 2003. The decrease resulted primarily from lower operating revenues, which were partially offset by lower operating expenses, net interest charges and preferred stock dividend requirements.

Operating revenues increased by $89 million or 5.2% in 2004 compared with 2003. Higher revenues resulted principally from a $136 million (44.2%) increase in wholesale sales (primarily to FES) due to increased nuclear generation available for sale which was partially offset by reduced generation sales revenue from franchise customers of $20 million. The reduction in retail generation revenues (residential - $9 million and commercial - $18 million) in 2004 reflected increases in electric generation service to residential and commercial customers provided by alternative suppliers as a percent of total sales deliveries in our franchise area of 5.5 percentage points and 8.2 percentage points, respectively. Reductions in residential and commercial revenues were partially offset by an $8 million increase in industrial retail generation revenues resulting from higher KWH sales (4.6%) to industrial customers due in part to a 2.7 percentage point reduction in the alternative suppliers’ share of industrial sales.

Revenues from distribution throughput decreased by $14 million in 2004 compared with 2003, even though total distribution deliveries increased by 1.4% in 2004. An improving economy increased distribution deliveries to commercial and industrial customers in 2004. Lower unit prices in all customer sectors in 2004 offset the effect of higher distribution deliveries to residential and industrial customers and partially offset higher sales to the commercial sector. Under the Ohio transition plan, we provide incentives to customers to encourage switching to alternative energy providers - $5 million of additional credits were provided to customers in 2004 compared with 2003. These revenue reductions are deferred for future recovery under our transition plan and do not affect current period earnings.

4

Operating revenues decreased $124 million or 6.7% in 2003 compared with 2002. The lower revenues were due to milder weather and increased sales by alternative suppliers. KWH sales to retail customers in all customer sectors (residential, commercial and industrial) declined by 13.6% in 2003 from the prior year, resulting in a $56 million reduction in generation sales revenue. KWH sales of electricity by alternative suppliers in our franchise area increased by 9 percentage points in 2003 from the prior year. Sales revenues from wholesale customers (primarily FES) decreased by $26 million in 2003 compared with 2002. The lower sales resulted from reductions in available nuclear generation of 17.2% in 2003 compared to 2002. Available generation decreased due to the extended outage of Davis-Besse and additional refueling activities at other nuclear generating units in 2003 compared to 2002. Customer shopping incentives further reduced operating revenues by $30 million in 2003 as compared with 2002. These revenue reductions are deferred for future recovery under the Ohio Transition Plan and do not materially affect current period earnings.

Changes in electric generation sales and distribution deliveries in 2004 and 2003, compared to the prior year, are summarized in the following table:

Changes in KWH Sales	2004			2003
Increase (Decrease)
Electric Generation:
Retail		(2.6	)%		(13.6	)%
Wholesale		44.2	%		(12.4	)%
Total Electric Generation Sales		20.4	%		(13.0	)%
Distribution Deliveries:
Residential		0.9	%		(2.9	)%
Commercial		2.7	%		1.3	%
Industrial		1.1	%		(0.1	)%
Total Distribution Deliveries		1.4	%		(0.5	)%

Operating Expenses and Taxes

Total operating expenses and taxes increased by $17 million in 2004 and decreased by $73 million in 2003 from the prior year. The following table presents changes from the prior year by expense category.

Operating Expenses and Taxes - Changes	2004			2003
	(In millions)
Increase (Decrease)
Fuel and purchased power costs	$	28		$	7
Nuclear operating costs		(124	)		34
Other operating costs		36			(43	)
Provision for depreciation		7			(38	)
Amortization of regulatory assets		30			17
Deferral of new regulatory assets		(24	)		(26	)
General taxes		10			(11	)
Income taxes		54			(13	)
Total operating expenses and taxes	$	17		$	(73	)

Higher fuel costs in 2004 compared to 2003 resulted principally from increased nuclear generation. Higher purchased power costs reflect higher unit costs and KWH purchased. The decrease in nuclear operating costs for 2004 was due to reduced incremental costs associated with the Davis-Besse extended outage and work performed during the Perry Plant’s 56-day refueling outage and the Beaver Valley Unit 2 refueling outage of 2003. Other operating costs increased in 2004, in part from higher employee benefit costs.

Higher fuel and purchased power costs in 2003 resulted from an increase in purchased power costs partially offset by lower fuel costs from reduced nuclear generation. Higher purchased power costs primarily reflect increased unit costs partially offset by lower power purchases from FES in 2003 compared to 2002. Increased nuclear costs resulted from unplanned work performed during the Perry Plant’s 56-day nuclear refueling outage and the Beaver Valley Unit 2 28-day refueling outage in 2003, compared with the 24-day refueling outage at Beaver Valley Unit 2 in 2002. The decrease in other operating costs in 2003 reflects lower employee costs - specifically the absence of short-term incentive compensation and reduced health care costs.

5

The increase in depreciation in 2004 compared to 2003 reflected a higher level of depreciable property in 2004, while the decrease in 2003 from 2002 was attributable to revised service life assumptions for nuclear generating plants, lower charges following the implementation of SFAS 143 ($18 million) and lower fossil plant depreciation ($14 million). Higher amortization of regulatory assets in 2004 and 2003 as compared to the prior periods was primarily due to increased amortization of transition regulatory assets. Increases in the deferral of regulatory assets in 2004 from 2003 were primarily a result of higher shopping incentive deferrals ($5 million) and deferred interest on the shopping incentives ($17 million). Increased shopping incentive deferrals were also the principal cause of the increase in 2003 compared to 2002.

General taxes increased $10 million in 2004 primarily due to the absence of settled property tax claims in 2003 and correspondingly decreased $11 million in 2003 from 2002 principally due to the settled property tax claims.

Other Income

Other income decreased by $55 million in 2004, principally due to a $131 million pre-tax NRG settlement recognized in 2003, partially offset by interest income from Shippingport, which was consolidated into CEI as of December 31, 2003. The increase in other income in 2003 compared to 2002 reflected the NRG gain in 2003.

Net Interest Charges

Net interest charges continued to trend lower, decreasing by $22 million in 2004 and by $29 million in 2003, due to our debt paydown program. Long-term debt interest was lower due to the redemptions of $289 million and refinancing of $46 million of pollution control notes during 2004. This decrease was partially offset by a $17 million increase in other interest expense resulting from Shippingport interest expense in 2004 (see Note 6 - Variable Interest Entities).

Cumulative Effect of Accounting Change

Upon adoption of SFAS 143 in the first quarter of 2003, we recorded an after-tax gain to net income of $42 million. The cumulative effect adjustment for unrecognized depreciation and accretion, offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component, was a $73 million increase to income, or $42 million net of income taxes.

Preferred Stock Dividend Requirements

Preferred stock dividend requirements decreased by $0.5 million in 2004 and decreased by $8 million in 2003 from 2002 principally due to optional redemptions of preferred stock in 2002. Premiums related to the optional redemptions partially offset the lower dividend requirements.

Capital Resources and Liquidity

Our cash requirements in 2004 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions were met without increasing our net debt and preferred stock outstanding. During 2005, we expect to meet our contractual obligations with cash from operations. Thereafter, we expect to use a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

As of December 31, 2004, CEI had $197,000 of cash and cash equivalents, compared with $25 million as of December 31, 2003. The major sources of changes in these balances are summarized below.

Cash Flows from Operating Activities

Cash provided by operating activities for 2004 compared with 2003 and 2002 were as follows:

Operating Cash Flows	2004			2003		2002
	(In millions)
Cash earnings (1)	$	443		$	309	$	229
Pension trust contribution(2)		(19	)		--		--
Working capital and other		(202	)		2		98
Total	$	222		$	311	$	327

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

⁽²⁾ Pension trust contribution net of $13 million income tax benefit.

6

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

Reconciliation of Cash Earnings	2004			2003			2002
	(In millions)
Net Income (GAAP)	$	237		$	239		$	137
Non-Cash Charges (Credits):
Provision for depreciation		132			125			163
Amortization of regulatory assets		196			166			149
Deferral of new regulatory assets		(117	)		(93	)		(67	)
Nuclear fuel and capital lease amortization		28			18			21
Other amortization		(18	)		(16	)		(15	)
Deferred operating lease costs, net		(56	)		(78	)		(60	)
Deferred income taxes and investment tax credits, net		26			22			(1	)
Accrued retirement benefit obligations		13			8			(104	)
Accrued compensation, net		2			(9	)		6
Cumulative effect of accounting change		--			(73	)		--
Cash earnings (Non-GAAP)	$	443		$	309		$	229

Net cash provided from operating activities decreased $89 million in 2004 compared to 2003 as a result of a $204 million decrease from changes in working capital and other cash flows and a $19 million after-tax voluntary pension trust contribution, partially offset by a $134 million increase in cash earnings as described under "Results of Operations". The decrease in working capital and other cash flows was principally due to a $149 million decrease in cash from accrued taxes payable, partially offset by a $55 million change in accounts receivable. Net cash from operating activities decreased $16 million in 2003 compared to 2002 as a result of a $96 million reduction in working capital and other requirements partially offset by a $80 million increase in cash earnings as described under "Results of Operations". The largest factor contributing to the decrease in working capital and other requirements was a $102 million decrease in cash from accounts payable.

Cash Flows from Financing Activities

Net cash used for financing activities decreased by $100 million in 2004 compared to 2003. The decrease in funds used for financing activities resulted from a reduction in net debt redemptions, partially offset by $170 million of common stock dividend payments to FirstEnergy in 2004.

The following table provides details regarding new issues and redemptions during 2004, 2003 and 2002:

Securities Issued or Redeemed	2004		2003			2002
	(In millions)
New Issues
Pollution Control Notes	$	125	$	--		$	107
Unsecured Notes		--		297			--
Redemptions
FMB		--		550			195
Pollution Control Notes		46		112			79
Secured Notes		288		15			33
Preferred Stock		1		1			165
Other		1		--			3
	$	336	$	678		$	475
Short-term Borrowings, Net	$	290	$	(109	)	$	191

We had about $0.7 million of cash and temporary investments (which include short-term notes receivable from associated companies) and approximately $489 million of short-term indebtedness as of December 31, 2004. We have obtained authorization from the PUCO to incur short-term debt of up to $500 million (including the utility money pool described below). We had the capability to issue $1.4 billion of additional FMB on the basis of property additions and retired bonds under the terms of our mortgage indenture. The issuance of FMB by CEI is subject to a provision of our 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 us to incur additional secured debt not otherwise permitted by a specified exception of up to $588 million as of December 31, 2004. We have no restrictions on the issuance of preferred stock.

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We have the ability to borrow from our regulated affiliates and FirstEnergy to meet our 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 2004 was 1.43%.

Our access to capital markets and costs of financing are dependent on the ratings of our securities and the securities of FirstEnergy. The following table shows securities ratings as of December 31, 2004. The ratings outlook from the rating agencies on all such securities is stable.

Ratings of Securities
	Securities		S&P		Moody’s		Fitch
FirstEnergy		Senior unsecured		BB+		Baa3		BBB-
CEI		Senior secured		BBB-		Baa2		BBB-
		Senior unsecured		BB+		Baa3		BB
		Preferred stock		BB		Ba2		BB-

On December 10, 2004, S&P reaffirmed FirstEnergy's ‘BBB-' corporate credit rating and kept the outlook stable. S&P noted that the stable outlook reflects FirstEnergy's improving financial profile and cash flow certainty through 2006. S&P stated that should the two refueling outages at the Davis-Besse and Perry nuclear plants scheduled for the first quarter of 2005 be completed successfully without any significant negative findings and delays, FirstEnergy's outlook would be revised to positive. S&P also stated that a ratings upgrade in the next several months did not seem likely, as remaining issues of concern to S&P, primarily the outcome of environmental litigation and SEC investigations, are not likely to be resolved in the short term.

Cash Flows from Investing Activities

Net cash used for investing activities increased $30 million in 2004 compared to 2003 and primarily reflected increased investments in lessor notes, partially offset by increased loan payments received from associated companies and lower expenditures for property additions. Net cash used for investing activities decreased by $39 million in 2003 compared to 2002 principally due to decreased property additions.

Our capital spending for the period 2005-2007 is expected to be about $368 million (excluding nuclear fuel) of which approximately $103 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to be approximately $76 million, of which about $11 million applies to 2005. During the same period, our nuclear fuel investments are expected to be reduced by approximately $91 million and $28 million, respectively, as the nuclear fuel is consumed.

Contractual Obligations

As of December 31, 2004, our estimated cash payments under existing contractual obligations that we consider firm obligations are as follows:

Contractual Obligations	Total		2005		2006-2007		2008-2009		Thereafter
	(In millions)
Long-term debt (4)	$	2,018	$	--	$	141	$	303	$	1,574
Short-term borrowings		489		489		--		--		--
Preferred stock (1)		4		1		2		1		--
Capital leases		8		1		2		2		3
Operating leases (2)		174		18		25		21		110
Purchases (3)		408		58		146		126		78
Total	$	3,101	$	567	$	316	$	453	$	1,765

⁽¹⁾ Subject to mandatory redemption.

⁽²⁾ Operating lease payments are net of capital trust receipts of $546.0 million (see Note 5).

⁽³⁾ Fuel and power purchases under contracts with fixed or minimum quantities and approximate timing.

⁽⁴⁾ Amounts reflected do not include interest on long-term debt.

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Off-Balance Sheet Arrangements

We have obligations not included on our Consolidated  Balance Sheet  related to sale and leaseback arrangements  involving the Bruce Mansfield Plant, which is reflected in the operating lease payments above (see Note 5 - Leases). As of December 31, 2004, the present value of these operating lease commitments, net of trust investments, total $115 million.

We sell substantially all of our retail customer receivables to CFC, our 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 $55 million of off-balance sheet financing as of December 31, 2004.

Interest Rate Risk

Our exposure to fluctuations in market interest rates is reduced since a significant portion of our debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for our investment portfolio, debt obligations and preferred stock with mandatory redemption provisions.

Comparison of Carrying Value to Fair Value
																There-						Fair
Year of Maturity	2005			2006			2007			2008			2009			after			Total			Value
	(Dollars in millions)
Assets
Investments Other Than Cash
and Cash Equivalents-
Fixed Income	$	33		$	45		$	36		$	39		$	41		$	640		$	834		$	954
Average interest rate		7.9	%		7.8	%		7.7	%		7.7	%		7.7	%		7.0	%		7.2	%
Liabilities
Long-term Debt and Other
Long-Term Obligations:
Fixed rate				$	12		$	129		$	140		$	163		$	1,205		$	1,649		$	1,821
Average interest rate					7.7	%		7.2	%		7.0	%		7.4	%		7.0	%		7.1	%
Variable rate																$	369		$	369		$	370
Average interest rate																	2.3	%		2.3	%
Preferred Stock Subject to
Mandatory Redemption	$	1		$	1		$	1		$	1								$	4		$	4
Average dividend rate		7.4	%		7.4	%		7.4	%		7.4	%								7.4	%
Short-term Borrowings	$	489																	$	489		$	489
Average interest rate		2.1	%																	2.1	%

Equity Price Risk

Included in our nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $242 million and $188 million as of December 31, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $24 million reduction in fair value as of December 31, 2004 (see Note 4 - Fair Value of Financial Instruments).

Outlook

Our industry continues to transition to a more competitive environment and all of our customers can select alternative energy suppliers. We continue to deliver power to residential homes and businesses through our existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. We 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 our customers elects to obtain power from an alternative supplier, we reduce the customer's bill with a "generation shopping credit," based on the regulated generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. We have continuing provider of last resort (PLR) responsibility to our franchise customers through December 31, 2005.

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Regulatory assets are costs which have been authorized by the PUCO and the FERC 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. Our regulatory assets as of December 2004 and 2003 were $ 1.0 billion and $1.1 billion, respectively. All regulatory assets are expected to continue to be recovered under the provisions of the transition and rate stabilization plans.

As part of the Ohio transition plan we are obligated to supply electricity to customers who do not choose an alternative supplier. We are also required to provide 400 MW of low cost supply to unaffiliated alternative suppliers who serve customers within our service area. Our competitive retail sales affiliate, FES, acts as an alternate supplier for a portion of the load in our franchise area.

On February 24, 2004, we filed a revised Rate Stabilization Plan to address PUCO concerns related to the original Rate Stabilization Plan. On June 9, 2004, the PUCO issued an order approving the revised Rate Stabilization Plan, subject to conducting a competitive bid process. On August 5, 2004, we accepted the Rate Stabilization Plan as modified and approved by the PUCO on August 4, 2004. In the second quarter of 2004, we implemented the accounting modifications related to the extended amortization periods and interest costs deferrals 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 our 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 cause us 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, we 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. We 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. Various parties have intervened in these cases.

On September 16, 2004, the FERC issued an order that imposed additional obligations on us under certain pre-Open Access transmission contracts among us and the cities of Cleveland and Painesville. Under the FERC’s decision, we may be responsible for a portion of new energy market charges imposed by MISO when its energy markets begin in the spring of 2005. We filed for rehearing of the order from the FERC on October 18, 2004. The impact of the FERC decision on us is dependent upon many factors, including the arrangements made by the cities for transmission service, the startup date for the MISO energy market, and the resolution of the rehearing request, and cannot be determined at this time.

See Note 8 to the consolidated financial statements for a more complete and detailed discussion of regulatory matters in Ohio.

Environmental Matters

We believe we are in compliance with current SO₂ and NO_x reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the EPA finalized regulations requiring additional NO_x reductions from our Ohio and Pennsylvania facilities. Various regulatory and judicial actions have since sought to further define NO_x reduction requirements. We continue to evaluate our compliance plans and other compliance options.

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Clean Air Act Compliance-

We 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. We cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

We believe we 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 our facilities. The EPA's NO_x Transport Rule imposes uniform reductions of NO_x emissions (an approximate 85% reduction in utility plant NO_x emissions from projected 2007 emissions) across a region of nineteen states (including 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. We believe our facilities are also complying with NO_x budgets established under State Implementation Plans (SIPs) 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 December 17, 2003, the EPA proposed the "Interstate Air Quality Rule" covering a total of 29 states (including Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air pollution emissions from 29 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. The EPA has proposed the Interstate Air Quality Rule to "cap-and-trade" NO_x and SO₂ emissions in two phases (Phase I in 2010 and Phase II in 2015). According to the EPA, SO₂ emissions would be reduced by approximately 3.6 million tons annually by 2010, across states covered by the rule, with reductions ultimately reaching more than 5.5 million tons annually. NO_x emission reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in 2015. The future cost of compliance with these proposed regulations may be substantial and will depend on whether and how they are ultimately implemented by the states in which we 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 December 15, 2003, the EPA proposed two different approaches to reduce mercury emissions from coal-fired power plants. The first approach would require plants to install controls known as MACT based on the type of coal burned. According to the EPA, if implemented, the MACT proposal would reduce nationwide mercury emissions from coal-fired power plants by 14 tons to approximately 34 tons per year. The second approach proposes a cap-and-trade program that would reduce mercury emissions in two distinct phases. Initially, mercury emissions would be reduced by 2010 as a "co-benefit" from implementation of SO₂ and NO_x emission caps under the EPA's proposed Interstate Air Quality Rule. Phase II of the mercury cap-and-trade program would be implemented in 2018 to cap nationwide mercury emissions from coal-fired power plants at 15 tons per year. The EPA has agreed to choose between these two options and issue a final rule by March 15, 2005. The future cost of compliance with these regulations may be substantial.

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.

We have 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 December 31, 2004, based on estimates of the total costs of cleanup, our proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. Included in Current Liabilities and Other Noncurrent Liabilities are accrued liabilities aggregating approximately $2.4 million as of December 31, 2004. We accrue environmental liabilities only when we can conclude that it is probable that we have an obligation for such costs and can reasonably determine the amount of such costs. Unasserted claims are reflected in our determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

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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% through 2012.

We 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 we generate is lower than many regional competitors due to our diversified generation sources which includes low or non-CO₂ emitting gas-fired and nuclear generators.

Clean Water Act-

Various water quality regulations, the majority of which are the result of the federal  Clean Water  Act and its amendments, apply to our plants.  In addition, Ohio and Pennsylvania have water quality standards applicable to our 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 and Pennsylvania have assumed such authority.

On September 7, 2004, the EPA established new performance standards under Clean Water Act Section 316(b) 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. We 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. Management 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.

Other Legal Proceedings

Power Outages and Related Litigation-

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 at the PUCO. The other two cases were appealed. One case was dismissed and no further appeal was sought. The remaining case is pending. 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 has been filed 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 our financial condition and results of operations.

Nuclear Plant Matters-

In late 2003, FENOC received a subpoena from a grand jury 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. FirstEnergy is unable to predict the outcome of this investigation. 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 relating to the Davis-Besse Nuclear Power Station outage 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. In addition, FENOC remains subject to possible civil enforcement action by the NRC in connection with the events leading to the Davis-Besse outage in 2002.

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On  August 12,  2004, the  NRC notified  FENOC  that it will 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 we have a 44.85% interest. Although the NRC noted that the plant continues to operate safely, the agency has indicated that its increased oversight will include an extensive NRC team inspection to assess the equipment problems and the sufficiency of FENOC's corrective actions. The outcome of these matters could include NRC enforcement action or other impacts on operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries financial condition.

Other Legal Matters-

Various lawsuits, claims (including claims for asbestos exposure) and proceedings related to our normal business operations are pending against us. The most significant not otherwise discussed above are described herein.

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.

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

Critical Accounting Policies

We prepare our consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of our assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Our more significant accounting policies are described below.

Regulatory Accounting

We are subject to regulation that sets the prices (rates) we are permitted to charge our customers based on the costs that the regulatory agencies determine we are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. We regularly review these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future.

Revenue Recognition

We follow the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled sales is recognized. The determination of unbilled sales requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class, weather-related impacts, prices in effect for each customer class and electricity provided by alternative suppliers.

Pension and Other Postretirement Benefits Accounting

Our reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions.

Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions we make to the plans, and earnings on plan assets. Such factors may be further affected by business combinations, which impact employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs.

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In accordance with SFAS 87, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience.

In selecting an assumed discount rate, we consider currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to recent declines in corporate bond yields and interest rates in general, we reduced the assumed discount rate as of December 31, 2004 to 6.00% from 6.25% and 6.75% used as of December 31, 2003 and 2002, respectively.

Our assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. In 2004, 2003 and 2002, plan assets actually earned 11.1%, 24.2% and (11.3)%, respectively. Our pension costs in 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and a pension trust investment allocation of approximately 68% equities, 29% bonds, 2% real estate and 1% cash.

In the third quarter of 2004, FirstEnergy made a $500 million voluntary contribution to its pension plan (our share was $32 million). Prior to this contribution, projections indicated that cash contributions of approximately $600 million would have been required during the 2006 to 2007 time period under minimum funding requirements established by the IRS. FirstEnergy's election to pre-fund the plan is expected to eliminate that funding requirement.

As a result of our voluntary contribution and the increased market value of pension plan assets, we reduced our accrued benefit cost as of December 31, 2004 by $30 million. As prescribed by SFAS 87, we reduced our additional minimum liability by $4 million, recording an increase in an intangible asset of $2 million and increasing OCI by $6 million. The balance in AOCL of $22 million (net of $15 million in deferred taxes) will reverse in future periods to the extent the fair value of trust assets exceeds the accumulated benefit obligation.

Health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2005 composite health care trend rate assumptions are approximately 10%-12% and 9%-11%, respectively, gradually decreasing to 5% in later years. In determining our trend rate assumptions, we included the specific provisions of our health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates.

Ohio Transition Cost Amortization

In connection  with our initial Ohio plan, the PUCO determined allowable transition costs based on amounts recorded on our regulatory books. These costs exceeded those deferred or capitalized on our balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). We use an effective interest method for amortizing transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in our Rate Stabilization Plan. In computing the transition cost amortization, we include only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received.

Long-Lived Assets

In accordance with SFAS 144, we periodically evaluate our long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, we recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows).

The calculation of future cash flows is based on assumptions, estimates and judgement about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment.

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Goodwill

In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, we evaluate our goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment were indicated, we would recognize a loss - calculated as the difference between the implied fair value of our goodwill and the carrying value of the goodwill. Our annual review was completed in the third quarter of 2004, with no impairment of goodwill indicated. The forecasts used in our evaluation of goodwill reflect operations consistent with our general business assumptions. Unanticipated changes in those assumptions could have a significant effect on our future evaluations of goodwill. As of December 31, 2004, we had approximately $1.7 billion of goodwill.

Nuclear Decommissioning

In accordance with SFAS 143, we recognize an ARO for the future decommissioning of our nuclear power plants. The ARO liability represents an estimate of the fair value of our current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. We used an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants' current license and settlement based on an extended license term.

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

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 EITF 03-1, which 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, we will continue to evaluate our investments as required by existing authoritative guidance.

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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31,	2004			2003			2002
	(In thousands)
OPERATING REVENUES (Note 2(I))	$	1,808,485		$	1,719,739		$	1,843,671
OPERATING EXPENSES AND TAXES:
Fuel and purchased power (Note 2(I))		622,021			593,816			587,108
Nuclear operating costs		117,091			240,971			207,313
Other operating costs (Note 2(I))		272,303			236,359			279,242
Provision for depreciation		131,854			125,467			163,443
Amortization of regulatory assets		196,501			166,343			148,611
Deferral of new regulatory assets		(117,466	)		(93,503	)		(67,327	)
General taxes		146,276			136,434			147,804
Income taxes		111,996			58,237			71,325
Total operating expenses and taxes		1,480,576			1,464,124			1,537,519
OPERATING INCOME		327,909			255,615			306,152
OTHER INCOME (NET OF INCOME TAXES) (Notes 2(I) and 7)		42,190			97,318			15,971
NET INTEREST CHARGES:
Interest on long-term debt		120,058			157,967			179,140
Allowance for borrowed funds used during construction		(5,110	)		(8,232	)		(4,331	)
Other interest expense		18,620			1,665			1,462
Subsidiary's preferred stock dividend requirements		--			4,500			8,900
Net interest charges		133,568			155,900			185,171
INCOME BEFORE CUMULATIVE EFFECT
OF ACCOUNTING CHANGE		236,531			197,033			136,952
Cumulative effect of accounting change (net of income
taxes of $30,168,000) (Note 2(G))		--			42,378			--
NET INCOME		236,531			239,411			136,952
PREFERRED STOCK DIVIDEND REQUIREMENTS		7,008			7,526			15,690
EARNINGS ON COMMON STOCK	$	229,523		$	231,885		$	121,262

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

16

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED BALANCE SHEETS

As of December 31,	2004		2003
ASSETS	(In thousands)
UTILITY PLANT:
In service	$	4,418,313	$	4,232,335
Less-Accumulated provision for depreciation		1,961,737		1,857,588
		2,456,576		2,374,747
Construction work in progress-
Electric plant		85,258		159,897
Nuclear fuel		30,827		21,338
		116,085		181,235
		2,572,661		2,555,982
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes (Note 6)		596,645		605,915
Nuclear plant decommissioning trusts		383,875		313,621
Long-term notes receivable from associated companies		97,489		107,946
Other		17,001		23,636
		1,095,010		1,051,118
CURRENT ASSETS:
Cash and cash equivalents		197		24,782
Receivables-
Customers		11,537		10,313
Associated companies		33,414		40,541
Other (less accumulated provisions of $293,000 and $1,765,000, respectively, for
uncollectible accounts)		152,785		185,179
Notes receivable from associated companies		521		482
Materials and supplies, at average cost		58,922		50,616
Prepayments and other		2,136		4,511
		259,512		316,424
DEFERRED CHARGES:
Regulatory assets		958,986		1,056,050
Goodwill		1,693,629		1,693,629
Property taxes		77,792		77,122
Other		32,875		23,123
		2,763,282		2,849,924
	$	6,690,465	$	6,773,448
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder’s equity	$	1,853,561	$	1,778,827
Preferred stock not subject to mandatory redemption		96,404		96,404
Long-term debt and other long-term obligations		1,970,117		1,884,643
		3,920,082		3,759,874
CURRENT LIABILITIES:
Currently payable long-term debt		76,701		387,414
Accounts payable-
Associated companies		150,141		245,815
Other		9,271		7,342
Notes payable to associated companies		488,633		188,156
Accrued taxes		129,454		202,522
Accrued interest		22,102		37,872
Lease market valuation liability		60,200		60,200
Other		61,131		76,722
		997,633		1,206,043
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		540,211		486,048
Accumulated deferred investment tax credits		60,901		65,996
Asset retirement obligation		272,123		254,834
Retirement benefits		82,306		105,101
Lease market valuation liability		668,200		728,400
Other		149,009		167,152
		1,772,750		1,807,531
COMMITMENTS AND CONTINGENCIES
(Notes 5 and 12)
	$	6,690,465	$	6,773,448

The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.

17

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

As of December 31,	2004		2003
(Dollars in thousands, except per share amounts)
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 (Note 2(F))		17,859		2,653
Retained earnings (Note 9(A))		553,740		494,212
Total common stockholder's equity		1,853,561		1,778,827

	Number of Shares				Optional
	Outstanding				Redemption Price
	2004		2003		Per Share		Aggregate
PREFERRED STOCK NOT SUBJECT TO
MANDATORY REDEMPTION(Note 9(B)):
Cumulative, without par value-
Authorized 4,000,000 shares
$ 7.40 Series A		500,000		500,000	$	101.00	$	50,500	50,000	50,000
Adjustable Series L		474,000		474,000		100.00		47,400	46,404	46,404
Total		974,000		974,000			$	97,900	96,404	96,404

LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS(Note 9(C)):
First mortgage bonds:
6.860% due 2008		125,000			125,000
Total first mortgage bonds		125,000			125,000
Unsecured notes:
6.000% due 2013		78,700			78,700
5.650% due 2013		300,000			300,000
9.000% due 2031		103,093			103,093
* 2.000% due 2033		27,700			27,700
		509,493			509,493
7.743% due to associated companies 2006-2016 (Note 6)		188,629			198,843
Total unsecured notes		698,122			708,336
Secured notes:
7.000% due 2005-2009		1,700			1,730
7.670% due 2004		--			280,000
7.130% due 2007		120,000			120,000
7.430% due 2009		150,000			150,000
* 1.850% due 2015		39,835			39,835
7.880% due 2017		300,000			300,000
* 1.850% due 2018		72,795			72,795
* 2.000% due 2020		47,500			47,500
6.000% due 2020		62,560			62,560
6.100% due 2020		70,500			70,500
9.520% due 2021		--			7,500
8.000% due 2023		--			46,100
7.625% due 2025		53,900			53,900
7.700% due 2025		43,800			43,800
7.750% due 2025		45,150			45,150
5.375% due 2028		5,993			5,993
* 1.700% due 2030		23,255			23,255
* 3.750% due 2030		81,640			--
* 1.800% due 2033		30,000			30,000
* 1.750% due 2033		46,100			--
Total secured notes		1,194,728			1,400,618
Preferred stock subject to mandatory redemption		4,009			5,014
Capital lease obligations (Note 5)		5,455			5,924
Net unamortized premium on debt		19,504			27,165
Long-term debt due within one year		(76,701	)		(387,414	)
Total long-term debt and other long-term obligations		1,970,117			1,884,643
TOTAL CAPITALIZATION	$	3,920,082		$	3,759,874

*  Denotes variable rate issue with December 31, 2004 interest rate shown.

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

18

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

								Accumulated
								Other
	Comprehensive			Number		Carrying		Comprehensive				Retained
	Income			of Shares		Value		Income (Loss)				Earnings
	(Dollars in thousands)
Balance, January 1, 2002					79,590,689	$	931,962	$	9,000		$	141,079
Net income	$	136,952										136,952
Unrealized loss on investments, net of
$(6,058,000) of income taxes		(9,233	)						(9,233	)
Minimum liability for unfunded retirement benefits,
net of $(31,359,000) of income taxes		(44,051	)						(44,051	)
Comprehensive income	$	83,668
Equity contribution from parent							50,000
Cash dividends on preferred stock												(10,965	)
Preferred stock redemption premiums												(4,743	)
Balance, December 31, 2002					79,590,689		981,962		(44,284	)		262,323
Net income	$	239,411										239,411
Unrealized gain on investments, net of
$19,598,000 of income taxes		28,255							28,255
Minimum liability for unfunded retirement benefits,
net of $13,760,000 of income taxes		18,682							18,682
Comprehensive income	$	286,348
Equity contribution from parent							300,000
Cash dividends on preferred stock												(7,429	)
Preferred stock redemption premiums												(93	)
Balance, December 31, 2003					79,590,689		1,281,962		2,653			494,212
Net income	$	236,531										236,531
Unrealized gain on investments, net of
$8,294,000 of income taxes		11,450							11,450
Minimum liability for unfunded retirement benefits,
net of $2,413,000 of income taxes		3,756							3,756
Comprehensive income	$	251,737
Cash dividends on preferred stock												(7,003	)
Cash dividends on common stock												(170,000	)
Balance, December 31, 2004					79,590,689	$	1,281,962	$	17,859		$	553,740

CONSOLIDATED STATEMENTS OF PREFERRED STOCK

	Not Subject to Mandatory Redemption						Subject to Mandatory Redemption
	Number			Carrying			Number			Carrying
	of Shares			Value			of Shares			Value
		(Dollars in thousands)
Balance, January 1, 2002		1,624,000		$	238,325			4,087,750		$	124,298
Redemptions-
$7.56 Series B		(450,000	)		(45,071	)
$42.40 Series T		(200,000	)		(96,850	)
$7.35 Series C								(10,000	)		(1,000	)
$90.00 Series S								(17,750	)		(17,010	)
Amortization of fair market
value adjustments-
$7.35 Series C											(9	)
$90.00 Series S											(258	)
Balance, December 31, 2002		974,000			96,404			4,060,000			106,021
Redemptions-
$7.35 Series C								(10,000	)		(1,000	)
FIN 46 Deconsolidation-
9.00% Series								(4,000,000	)		(100,000	)
Amortization of fair market
value adjustments-
$7.35 Series C											(7	)
Balance, December 31, 2003		974,000			96,404			50,000			5,014*
Redemptions -
$7.35 Series C								(10,000	)		(1,000	)
Amortization of fair market
value adjustments-
$7.35 Series C											(5	)
Balance, December 31, 2004		974,000		$	96,404			40,000		$	4,009*

* Preferred stock subject to mandatory redemption is classified as debt under SFAS 150.

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

19

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31,	2004			2003			2002
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	236,531		$	239,411		$	136,952
Adjustments to reconcile net income to net
cash from operating activities:
Provision for depreciation		131,854			125,467			163,443
Amortization of regulatory assets		196,501			166,343			148,611
Deferral of new regulatory assets		(117,466	)		(93,503	)		(67,327	)
Nuclear fuel and capital lease amortization		28,239			17,466			21,044
Amortization of electric service obligation		(18,386	)		(16,278	)		(15,008	)
Deferred rents and lease market valuation liability		(56,405	)		(78,214	)		(60,200	)
Deferred income taxes and investment tax credits, net		39,129			22,332			(995	)
Accrued retirement benefit obligations		13,245			7,630			(103,448	)
Accrued compensation, net		2,433			(8,743	)		6,372
Cumulative effect of accounting change (Note 2(G))		--			(72,546	)		--
Pension trust contribution		(31,718	)		--			--
Decrease (Increase) in operating assets:
Receivables		38,297			(16,339	)		(27,159	)
Materials and supplies		(8,306	)		5,771			(7,624	)
Prepayments and other current assets		2,375			(294	)		27,418
Increase (Decrease) in operating liabilities:
Accounts payable		(93,745	)		(54,858	)		47,147
Accrued taxes		(73,068	)		76,261			(3,568	)
Accrued interest		(15,770	)		(13,895	)		(5,334	)
Other		(51,617	)		4,754			66,933
Net cash provided from operating activities		222,123			310,765			327,257
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		124,977			296,905			106,981
Short-term borrowings, net		290,263			--			190,879
Equity contributions from parent		--			300,000			50,000
Redemptions and Repayments-
Preferred stock		(1,000	)		(1,093	)		(164,674	)
Long-term debt		(335,393	)		(677,097	)		(309,480	)
Short-term borrowings, net		--			(109,212	)		--
Dividend Payments-
Common stock		(170,000	)		--			--
Preferred stock		(7,008	)		(7,451	)		(13,782	)
Net cash used for financing activities		(98,161	)		(197,948	)		(140,076	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(121,316	)		(134,899	)		(163,199	)
Loan repayments from (payments to) associated companies, net		10,418			(5,003	)		415
Investment in lessor notes (Note 6)		9,270			44,732			39,636
Contributions to nuclear decommissioning trusts		(29,024	)		(29,024	)		(29,024	)
Other		(17,895	)		5,777			(4,923	)
Net cash used for investing activities		(148,547	)		(118,417	)		(157,095	)
Net increase (decrease) in cash and cash equivalents		(24,585	)		(5,600	)		30,086
Cash and cash equivalents at beginning of year		24,782			30,382			296
Cash and cash equivalents at end of year	$	197		$	24,782		$	30,382
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	152,373		$	174,375		$	186,040
Income taxes	$	144,277		$	24,796		$	121,668

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

20

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF TAXES

For the Years Ended December 31,	2004			2003			2002
	(In thousands)
GENERAL TAXES:
Real and personal property	$	74,206		$	63,448		$	77,516
Ohio kilowatt-hour excise*		66,974			68,459			66,775
Social security and unemployment		4,496			4,331			3,478
Other		600			196			35
Total general taxes	$	146,276		$	136,434		$	147,804
PROVISION FOR INCOME TAXES:
Currently payable-
Federal	$	72,264		$	109,775		$	76,364
State		27,463			29,346			14,721
		99,727			139,121			91,085
Deferred, net-
Federal		34,450			21,382			(3,661	)
State		9,775			5,757			2,146
		44,225			27,139			(1,515	)
Investment tax credit amortization		(5,096	)		(4,807	)		(4,632	)
Total provision for income taxes	$	138,856		$	161,453		$	84,938
INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income	$	111,996		$	58,237		$	71,325
Other income		26,860			73,048			13,613
Cumulative effect of accounting change		--			30,168			--
Total provision for income taxes	$	138,856		$	161,453		$	84,938
RECONCILIATION OF FEDERAL INCOME TAX
EXPENSE AT STATUTORY RATE TO TOTAL
PROVISION FOR INCOME TAXES:
Book income before provision for income taxes	$	375,387		$	400,864		$	221,890
Federal income tax expense at statutory rate	$	131,385		$	140,302		$	77,662
Increases (reductions) in taxes resulting from-
State income taxes, net of federal income tax benefit		24,205			22,817			10,964
Amortization of investment tax credits		(5,096	)		(4,807	)		(4,632	)
Amortization of tax regulatory assets		1,156			1,087			999
Other, net		(12,794	)		2,054			(55	)
Total provision for income taxes	$	138,856		$	161,453		$	84,938
ACCUMULATED DEFERRED INCOME TAXES AT
DECEMBER 31:
Property basis differences		502,625		$	477,358		$	473,506
Regulatory transition charge		221,386			302,270			371,486
Unamortized investment tax credits		(23,208	)		(25,311	)		(27,839	)
Deferred gain for asset sale to affiliated company		33,841			38,394			43,193
Other comprehensive income		12,548			1,841			(31,517	)
Above market leases		(300,000	)		(324,843	)		(350,299	)
Retirement benefits		(21,674	)		(32,023	)		(42,079	)
Shopping credit incentive deferral		121,778			73,804			35,203
Other		(7,085	)		(25,442	)		(64,357	)
Net deferred income tax liability	$	540,211		$	486,048		$	407,297

* Collected from customers through regulated rates and included in revenue in the Consolidated Statements of Income.

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

21

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.   ORGANIZATION AND BASIS OF PRESENTATION:

The consolidated financial statements include CEI (Company) and its wholly owned subsidiaries, CFC and Shippingport (see Note 6). The Company is a wholly owned subsidiary of FirstEnergy. FirstEnergy also holds directly all of the issued and outstanding common shares of its other principal electric utility operating subsidiaries, including OE, TE, ATSI, JCP&L, Met-Ed and Penelec.

The Company follows GAAP and complies with the regulations, orders, policies and practices prescribed by the SEC, PUCO and the FERC. 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 the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Certain 2003 revenues and expenses have been reclassified and presented on a net basis to conform to the current year presentation.

The Company consolidates all majority-owned subsidiaries over which the Company exercises control and, when applicable, entities for which the Company has 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 the Company has the ability to exercise significant influence, but not control, are accounted for on the equity basis.

Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.

2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

(A)   ACCOUNTING FOR THE EFFECTS OF REGULATION-

The Company accounts for the effects of regulation through the application of SFAS 71 when its rates:

are established by a third-party regulator with the authority to set rates that bind customers;

are cost-based; and

can be charged to and collected from customers.

An enterprise meeting all of these criteria capitalizes costs that would otherwise be charged to expense if the rate actions of its regulator make it probable that those costs will be recovered in future revenue. SFAS 71 is applied only to the parts of the business that meet the above criteria. If a portion of the business applying SFAS 71 no longer meets those requirements, previously recorded regulatory assets are removed from the balance sheet in accordance with the guidance in SFAS 101.

Regulatory Assets-

The Company recognizes, as regulatory assets, costs which the FERC and the PUCO 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 Company’s transition plan. Based on that plan, the Company continues to bill and collect cost-based rates for its transmission and distribution services, which will remain regulated; accordingly, it is appropriate that the Company continues the application of SFAS 71 to those operations.

Net regulatory assets on the Consolidated Balance Sheets are comprised of the following:

	2004			2003
	(In millions)
Regulatory transition costs	$	705		$	900
Customer shopping incentives		295			179
Customer receivables for future income taxes		6			7
Loss on reacquired debt		13			14
Employee postretirement benefit costs		13			15
Asset removal costs		(75	)		(60	)
Other		2			1
Total	$	959		$	1,056

22

The Company is deferring customer shopping incentives and interest costs as new regulatory assets in accordance with the transition and rate stabilization plans. These regulatory assets, totaling $295 million as of December 31, 2004, 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. The Company expects to recover these deferred customer shopping incentives before the end of 2010.

Transition Cost Amortization-

The Company amortizes transition costs (see Regulatory Matters) using the effective interest method. Under the Rate Stabilization Plan, total transition cost amortization is expected to approximate the following for 2005 through 2009.

	(In millions)
2005	$	222
2006		126
2007		139
2008		159
2009		54

Accounting for Generation Operations-

The application of SFAS 71 was discontinued prior to 2001 with respect to the Company's generation operations. The SEC's interpretive guidance regarding asset impairment measurement providing that any supplemental regulated cash flows such as a CTC should be excluded from the cash flows of assets in a portion of the business not subject to regulatory accounting practices. If those assets are impaired, a regulatory asset should be established if the costs are recoverable through regulatory cash flows. Consistent with the SEC guidance and EITF 97-4, $304 million of impaired plant investments were recognized by the Company as regulatory assets recoverable as transition costs through future regulatory cash flows. Net assets included in utility plant relating to the operations for which the application of SFAS 71 was discontinued were $1.3 billion as of December 31, 2004.

(B)   CASH AND SHORT-TERM FINANCIAL INSTRUMENTS-

All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Cash and cash equivalents as of December 31, 2003 included $25 million which was included in the NRG settlement claim sold in January 2004 (see Note 7).

(C)   REVENUES AND RECEIVABLES-

The Company's principal business is providing electric service to customers in Ohio. The Company's retail customers are metered on a cycle basis. Electric revenues are recorded based on energy delivered through the end of the calendar month. An estimate of unbilled revenues is calculated to recognize electric service provided between the last meter reading and the end of the month. This estimate includes many factors including estimated weather impacts, customer shopping activity, historical line loss factors and prices in effect for each class of customer. In each accounting period, the Company accrues the estimated unbilled amount receivable as revenue and reverses the related prior period estimate.

Receivables from customers include sales to residential, commercial and industrial customers located in the Company's service area and sales to wholesale customers. There was no material concentration of receivables as of December 31, 2004 or 2003, with respect to any particular segment of the Company's customers. Total customer receivables were $12 million (billed - $9 million and unbilled - $3 million) and $10 million (billed - $6 million and unbilled - $4 million) as of December 31, 2004 and 2003, respectively.

The Company and TE sell substantially all of their retail customer receivables to CFC. CFC subsequently transfers the receivables to a trust under an asset-backed securitization agreement. The trust is a "qualified special purpose entity" under SFAS 140, which provides it with certain rights relative to the transferred assets. Transfers are made in return for an interest in the trust (62% as of December 31, 2004), which is stated at fair value, reflecting adjustments for anticipated credit losses. The fair value of CFC's interest in the trust approximates the stated value of its retained interest in the underlying receivables, after adjusting for anticipated credit losses, because the average collection period is 27 days. Accordingly, subsequent measurements of the retained interest under SFAS 115, (as an available-for-sale financial instrument) result in no material change in value. Sensitivity analyses reflecting 10% and 20% increases in the rate of anticipated credit losses would not have significantly affected FirstEnergy's retained interest in the pool of receivables through the trust.

23

Of the $222 million sold to the trust and outstanding as of December 31, 2004, FirstEnergy retained interests in $138 million of the receivables. Accordingly, receivables recorded as other receivables on the Consolidated Balance Sheets were reduced by approximately $84 million due to these sales. Collections of receivables previously transferred to the trust and used for the purchase of new receivables from CFC during 2004 totaled approximately $2.5 billion. CEI and TE processed receivables for the trust and received servicing fees of approximately $4.8 million ($3.2 million - the Company and $1.6 million - TE) in 2004. Expenses associated with the factoring discount related to the sale of receivables were $3.5 million in 2004.

(D)   UTILITY PLANT AND DEPRECIATION-

Utility plant reflects original cost of construction (except for the Company's nuclear generating units which were adjusted to fair value), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. The Company's accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred.

The Company provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annualized composite rate was approximately 2.8% in 2004 and 2003, and 3.6% in 2002.

Jointly - Owned Generating Stations-

The Company, together with TE, OE and Penn, own and/or lease, as tenants in common, various power generating facilities. Each of the companies is obligated to pay a share of the costs associated with any jointly-owned facility in the same proportion as its interest. The Company’s portion of operating expenses associated with jointly-owned facilities is included in the corresponding operating expenses on the Consolidated Statements of Income. The amounts reflected on the Consolidated Balance Sheet under utility plant as of December 31, 2004 include the following:

	Utility		Accumulated		Construction		Ownership/
	Plant		Provision for		Work in		Leasehold
Generating Units	in Service		Depreciation		Progress		Interest
	(In millions)
W. H. Sammis Unit 7	$	179	$	127	$	--		31.20	%
Bruce Mansfield Units 1, 2 and 3		153		46		9		20.42	%
Beaver Valley Unit 2		19		1		12		24.47	%
Davis-Besse		308		63		34		51.38	%
Perry		663		172		11		44.85	%
Total	$	1,322	$	409	$	66

The Bruce Mansfield Plant is being leased (see Note 5) and the above-related amounts represent construction expenditures subsequent to the sale and leaseback transaction.

Nuclear Fuel-

Nuclear fuel is recorded at original cost, which includes material, enrichment, fabrication and interest costs incurred prior to reactor load. The Company amortizes the cost of nuclear fuel based on the units of production method.

(E)   ASSET IMPAIRMENTS-

Long-Lived Assets-

The Company evaluates the carrying value of its long-lived assets when events or circumstances indicate that the carrying amount may not be recoverable. In accordance with SFAS 144, the carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If an impairment exists, a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. Fair value is estimated by using available market valuations or the long-lived asset's expected future net discounted cash flows. The calculation of expected cash flows is based on estimates and assumptions about future events.

24

Goodwill-

In a business combination, the excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, the Company evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If an impairment is indicated, the Company recognizes a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. The Company's 2004 annual review was completed in the third quarter of 2004 with no impairment indicated. The forecasts used in the Company's evaluation of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on its future evaluations of goodwill. As of December 31, 2004, the Company had approximately $1.7 billion of goodwill. The impairment analysis includes a significant source of cash representing the Company's recovery of transition costs as described below under "Regulatory Matters." The Company estimates that completion of transition cost recovery will not result in an impairment of goodwill.

Investments-

The Company periodically evaluates for impairment investments that include available-for-sale securities held by its nuclear decommissioning trusts. In accordance with SFAS 115, securities classified as available-for-sale are evaluated to determine whether a decline in fair value below the cost basis is other than temporary. If the decline in fair value is determined to be other than temporary, the cost basis of the security is written down to fair value. The Company considers, among other factors, the length of time and the extent to which the security's fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating investments for impairment. The fair value and unrealized gains and losses of the Company's investments are disclosed in Note 4.

(F)   COMPREHENSIVE INCOME-

Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholder's equity except those resulting from transactions with FirstEnergy and preferred stockholders. As of December 31, 2004, accumulated other comprehensive income consisted of a minimum liability for unfunded retirement benefits of $22 million and unrealized gains on investments in securities available for sale of $40 million. As of December 31, 2003, accumulated other comprehensive loss consisted of a minimum liability for unfunded retirement benefits of $25 million and unrealized gains on investments in securities available for sale of $28 million.

(G)   CUMULATIVE EFFECT OF ACCOUNTING CHANGE-

Results for 2003 include an after-tax credit to net income of $42.4 million recorded by the Company upon adoption of SFAS 143 in January of 2003. The Company identified applicable legal obligations as defined under the new accounting standard for nuclear power plant decommissioning, reclamation of a sludge disposal pond at the Bruce Mansfield Plant, and closure of two coal ash disposal sites. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $49.9 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $6.8 million. The asset retirement obligation liability at the date of adoption was $238.3 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, the Company had recorded decommissioning liabilities of $242.5 million. The cumulative effect adjustment for unrecognized depreciation and accretion, offset by the reduction in the existing decommissioning liabilities and the reversal of accumulated estimated removal costs for non-regulated generation assets, was a $72.5 million increase to income, or $42.4 million net of income taxes.

(H)   INCOME TAXES-

Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. The Company records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled. The Company is included in FirstEnergy's consolidated federal income tax return. The consolidated tax liability is allocated on a "stand-alone" company basis, with each Company recognizing any tax losses or credits the Company contributes to the consolidated return.

25

(I)   TRANSACTIONS WITH AFFILIATED COMPANIES-

Operating revenues, operating expenses and other income include transactions with affiliated companies, primarily ATSI, FES and FESC. The Ohio transition plan, as discussed in the "Regulatory Matters" section, resulted in the corporate separation of FirstEnergy's regulated and unregulated operations in 2001. FES operates the generation businesses of the Company, TE, OE and Penn. As a result, the Company entered into power supply agreements (PSA) whereby FES purchases all of the Company's nuclear generation and the generation from leased fossil generating facilities and the Company purchases its power from FES to meet its "provider of last resort" obligations. In the fourth quarter of 2003, ATSI transferred operational control of its transmission facilities to MISO and previously affiliated transmission service expenses are now provided under the MISO Open Access Transmission Tariff. CFC serves as the transferor in connection with the accounts receivable securitization for the Company and TE. The primary affiliated companies transactions are as follows:

	2004		2003		2002
	(In millions)
Operating Revenues:
PSA revenues from FES	$	387	$	260	$	284
Generating units rent from FES		59		59		60
Ground lease with ATSI		7		7		7
Operating Expenses:
Purchased power under PSA		444		423		420
Purchased power from TE		101		109		104
Transmission expenses		--		32		41
FESC support services		65		63		52
Other Income:
Interest income from ATSI		7		7		7
Interest income from FES		--		1		1

The Company is buying 150 MW of TE's Beaver Valley Unit 2 leased capacity entitlement. Purchased power expenses for this transaction were $101 million, $109 million and $104 million in 2004, 2003 and 2002, respectively. This purchase is expected to continue through the end of the lease period (see Note 5).

FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Company from FESC, a subsidiary of FirstEnergy and a "mutual service company" as defined in Rule 93 of the PUHCA. The majority of costs are directly billed or assigned at no more than cost as determined by PUHCA Rule 91. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas that are filed annually with the SEC on Form U-13-60. The current allocation or assignment formulas used and their bases include multiple factor formulas; each company's proportionate amount of FirstEnergy's aggregate direct payroll, number of employees, asset balances, revenues, number of customers, other factors and specific departmental charge ratios. Management believes that these allocation methods are reasonable. Intercompany transactions with FirstEnergy and its other subsidiaries are generally settled under commercial terms within thirty days, except for $84 million payable to affiliates for OPEB obligations.

3.   PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS:

FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees. The trusteed plans provide defined benefits based on years of service and compensation levels. The Company's funding policy is based on actuarial computations using the projected unit credit method. In the third quarter of 2004, FirstEnergy made a $500 million voluntary contribution to its pension plan (Company's share was $32 million). Prior to this contribution, projections indicated that cash contributions of approximately $600 million would have been required during the 2006 to 2007 time period under minimum funding requirements established by the IRS. The election to pre-fund the plan is expected to eliminate that funding requirement. Since the contribution is deductible for tax purposes, the after-tax cash impact of the voluntary contribution is approximately $300 million (Company’s share was $19 million).

FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and copayments, are also available to retired employees, their dependents and, under certain circumstances, their survivors. The Company recognizes the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits.

26

Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans, and earnings on plan assets. Such factors may be further affected by business combinations, which impact employee demographics, plan experience and other factors. Pension and OPEB costs may also be affected by changes in key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations and pension and OPEB costs. FirstEnergy uses a December 31 measurement date for the majority of its plans.

Unless otherwise indicated, the following tables provide information applicable to FirstEnergy's pension and OPEB plans.

Obligations and Funded Status	Pension Benefits						Other Benefits
As of December 31
	2004			2003			2004			2003
	(In millions)
Change in benefit obligation
Benefit obligation as of January 1	$	4,162		$	3,866		$	2,368		$	2,077
Service cost		77			66			36			43
Interest cost		252			253			112			136
Plan participants’ contributions		--			--			14			6
Plan amendments		--			--			(281	)		(123	)
Actuarial (gain) loss		134			222			(211	)		323
Benefits paid		(261	)		(245	)		(108	)		(94	)
Benefit obligation as of December 31	$	4,364		$	4,162		$	1,930		$	2,368
Change in fair value of plan assets
Fair value of plan assets as of January 1	$	3,315		$	2,889		$	537		$	473
Actual return on plan assets		415			671			57			88
Company contribution		500			--			64			68
Plan participants’ contribution		--			--			14			2
Benefits paid		(261	)		(245	)		(108	)		(94	)
Fair value of plan assets as of December 31	$	3,969		$	3,315		$	564		$	537
Funded status	$	(395	)	$	(847	)	$	(1,366	)	$	(1,831	)
Unrecognized net actuarial loss		885			919			730			994
Unrecognized prior service cost (benefit)		63			72			(378	)		(221	)
Unrecognized net transition obligation		--			--			--			83
Net asset (liability) recognized	$	553		$	144		$	(1,014	)	$	(975	)
Amounts Recognized in the
Consolidated Balance Sheets
As of December 31
Accrued benefit cost	$	(14	)	$	(438	)	$	(1,014	)	$	(975	)
Intangible assets		63			72			--			--
Accumulated other comprehensive loss		504			510			--			--
Net amount recognized	$	553		$	144		$	(1,014	)	$	(975	)
Company's share of net amount recognized	$	47		$	22		$	(77	)	$	(71	)
Increase (decrease) in minimum liability included in other comprehensive income (net of tax)	$	(4	)	$	(145	)		--			--
Assumptions Used to Determine
Benefit Obligations As of December 31
Discount rate		6.00	%		6.25	%		6.00	%		6.25	%
Rate of compensation increase		3.50	%		3.50	%
Allocation of Plan Assets
As of December 31
Asset Category
Equity securities		68	%		70	%		74	%		71	%
Debt securities		29			27			25			22
Real estate		2			2			--			--
Cash		1			1			1			7
Total		100	%		100	%		100	%		100	%

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Information for Pension Plans With an Accumulated Benefit Obligation in Excess of Plan Assets	2004		2003
	(In millions)
Projected benefit obligation	$	4,364	$	4,162
Accumulated benefit obligation		3,983		3,753
Fair value of plan assets		3,969		3,315

	Pension Benefits									Other Benefits
Components of Net Periodic Benefit Costs	2004			2003			2002			2004			2003			2002
	(In millions)
Service cost	$	77		$	66		$	59		$	36		$	43		$	29
Interest cost		252			253			249			112			137			114
Expected return on plan assets		(286	)		(248	)		(346	)		(44	)		(43	)		(52	)
Amortization of prior service cost		9			9			9			(40	)		(9	)		3
Amortization of transition obligation (asset)		--			--			--			--			9			9
Recognized net actuarial loss		39			62			--			39			40			11
Net periodic cost (income)	$	91		$	142		$	(29	)	$	103		$	177		$	114
Company's share of net periodic cost	$	6		$	10		$	1		$	18		$	15		$	10

Weighted-Average Assumptions Used
to Determine Net Periodic Benefit Cost	Pension Benefits									Other Benefits
for Years Ended December 31	2004			2003			2002			2004			2003			2002
Discount rate		6.25	%		6.75	%		7.25	%		6.25	%		6.75	%		7.25	%
Expected long-term return on plan assets		9.00	%		9.00	%		10.25	%		9.00	%		9.00	%		10.25	%
Rate of compensation increase		3.50	%		3.50	%		4.00	%

In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. The assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by the Company's pension trusts. The long-term rate of return is developed considering the portfolio’s asset allocation strategy.

FirstEnergy employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalizations. Other assets such as real estate are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.

Assumed Health Care Cost Trend Rates
As of December 31	2004			2003
Health care cost trend rate assumed for next
year (pre/post-Medicare)		9%-11	%		10%-12	%
Rate to which the cost trend rate is assumed to
decline (the ultimate trend rate)		5	%		5	%
Year that the rate reaches the ultimate trend
rate (pre/post-Medicare)		2009-2011			2009-2011

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	1-Percentage-		1-Percentage
	Point Increase		Point Decrease
	(In millions)
Effect on total of service and interest cost	$	19	$	(16	)
Effect on postretirement benefit obligation	$	205	$	(179	)

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Pursuant to FSP 106-1 issued January 12, 2004, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 because of a plan amendment during the quarter, which required remeasurement of the plan's obligations. The plan amendment, which increases cost-sharing by employees and retirees effective January 1, 2005, reduced the Company's postretirement benefit costs by $9 million during 2004.

Consistent with the guidance in FSP 106-2 issued on May 19, 2004, FirstEnergy recognized a reduction of $318 million in the accumulated postretirement benefit obligation as a result of the federal subsidy provided under the Medicare Act related to benefits for past service. This reduction was accounted for as an actuarial gain in 2004 pursuant to FSP 106-2. The subsidy reduced the Company's net periodic postretirement benefit costs by $7 million during 2004.

As a result of its voluntary contribution and the increased market value of pension plan assets, the Company reduced its accrued benefit cost as of December 31, 2004 by $30 million. As prescribed by SFAS 87, the Company reduced its additional minimum liability by $4 million, recording an increase in an intangible asset of $2 million and crediting OCI by $6 million. The balance in AOCL of $22 million (net of $15 million in deferred taxes) will reverse in future periods to the extent the fair value of trust assets exceeds the accumulated benefit obligation.

Taking into account estimated employee future service, FirstEnergy expects to make the following benefit payments from plan assets:

	Pension Benefits		Other Benefits
	(In millions)
2005	$	228	$	111
2006		228		106
2007		236		109
2008		247		112
2009		264		115
Years 2010 - 2014		1,531		627

4.   FAIR VALUE OF FINANCIAL INSTRUMENTS:

Long-term Debt and Other Long-term Obligations-

All borrowings with initial maturities of less than one year are defined as financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value. The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations as of December 31:

	2004				2003
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Long-term debt	$	1,915	$	2,079	$	2,131	$	2,331
Subordinated debentures to affiliated trusts		103		112		103		113
Preferred stock subject to mandatory redemption		4		4		5		5
	$	2,022	$	2,195	$	2,239	$	2,449

The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by a corporation with credit ratings similar to the Company's ratings.

Investments-

The carrying amounts of cash and cash equivalents approximate fair value due to the short-term nature of these investments. The following table provides the approximate fair value and related carrying amounts of investments other than cash and cash equivalents as of December 31:

29

	2004				2003
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Debt securities:(1)
-Government obligations	$	100	$	100	$	85	$	85
-Corporate debt securities(2)		734		854		754		868
		834		954		839		953
Equity securities(1)		242		242		188		188
	$	1,076	$	1,196	$	1,027	$	1,141

⁽¹⁾ Includes nuclear decommissioning trust investments.

⁽²⁾ Includes investments in lease obligation bonds (see Note 5).

The fair value of investments other than cash and cash equivalents represent cost (which approximates fair value) or the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms.

Investments other than cash and cash equivalents include held-to-maturity securities and available-for-sale securities. Decommissioning trust investments are classified as available-for-sale. The Company has no securities held for trading purposes. The following table summarizes the amortized cost basis, gross unrealized gains and losses and fair values for decommissioning trust investments as of December 31:

	2004								2003
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
	(In millions)
Debt securities	$	140	$	2	$	--	$	142	$	119	$	7	$	1	$	125
Equity securities		177		69		4		242		148		52		12		188
	$	317	$	71	$	4	$	384	$	267	$	59	$	13	$	313

Proceeds from the sale of decommissioning trust investments, gross realized gains and losses on those sales, and interest and dividend income for the three years ended December 31, 2004 were as follows:

	2004		2003		2002
	(In millions)
Proceeds from sales	$	411	$	226	$	198
Gross realized gains		35		15		15
Gross realized losses		21		16		22
Interest and dividend income		11		9		7

The following table provides the fair value and gross unrealized losses of nuclear decommissioning trust investments that are deemed to be temporarily impaired as of December 31, 2004.

	Less Than 12 Months				12 Months or More				Total
	Fair		Unrealized		Fair		Unrealized		Fair		Unrealized
	Value		Losses		Value		Losses		Value		Losses
	(In millions)
Debt securities	$	50	$	--	$	1	$	--	$	51	$	--
Equity securities		38		2		6		2		44		4
	$	88	$	2	$	7	$	2	$	95	$	4

The Company periodically evaluates the securities held by its nuclear decommissioning trusts for other-than-temporary impairment. The Company considers the length of time and the extent to which the security's fair value has been less than its cost basis and other factors to determine whether an impairment is other than temporary.

30

Unrealized gains and losses applicable to the Company's decommissioning trusts are recognized in OCI in accordance with SFAS 115, as fluctuations in the fair value of these trust balances will eventually affect earnings.

The investment policy for the nuclear decommissioning trust funds restricts or limits the ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust fund's custodian or managers and their parents or subsidiaries.

5.   LEASES:

The Company leases certain generating facilities, office space and other property and equipment under cancelable and noncancelable leases.

The Company and TE sold their ownership interests in Bruce Mansfield Units 1, 2 and 3 and TE sold a portion of its ownership interest in Beaver Valley Unit 2. In connection with these sales, which were completed in 1987, the Company and TE entered into operating leases for lease terms of approximately 30 years as co-lessees. During the terms of the leases, the Company and TE continue to be responsible, to the extent of their combined ownership and leasehold interest, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. The Company and TE have the right, at the end of the respective basic lease terms, to renew the leases. The Company and TE also have the right to purchase the facilities at the expiration of the basic lease term or any renewal term at a price equal to the fair market value of the facilities.

As co-lessee with TE, the Company is also obligated for TE's lease payments. If TE is unable to make its payments under the Beaver Valley Unit 2 and Bruce Mansfield Plant leases, the Company would be obligated to make such payments. No such payments have been made on behalf of TE. (TE's future minimum lease payments as of December 31, 2004 were approximately $0.9 billion, net of trust cash receipts.)

Consistent with the regulatory treatment, the rentals for capital and operating leases are charged to operating expenses on the Consolidated Statements of Income. Such costs for the three years ended December 31, 2004 are summarized as follows:

	2004		2003		2002
	(In millions)
Operating leases
Interest element	$	28.6	$	31.6	$	33.6
Other		27.1		45.9		42.8
Capital leases
Interest element		0.5		0.6		0.6
Other		0.5		0.4		0.4
Total rentals	$	56.7	$	78.5	$	77.4

The future minimum lease payments as of December 31, 2004 are:

			Operating Leases
	Capital		Lease		Capital
	Leases		Payments		Trust		Net
	(In millions)
2005	$	1.0	$	66.7	$	48.3	$	18.4
2006		1.0		71.3		56.2		15.1
2007		1.0		57.8		48.2		9.6
2008		1.0		54.2		42.9		11.3
2009		1.0		56.1		46.1		10.0
Years thereafter		2.7		414.4		304.3		110.1
Total minimum lease payments		7.7	$	720.5	$	546.0	$	174.5
Interest portion		2.2
Present value of net minimum lease payments		5.5
Less current portion		0.5
Noncurrent portion	$	5.0

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The Company has recorded above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant associated with the 1997 merger creating FirstEnergy. The total above-market lease obligation of $611 million associated with Beaver Valley Unit 2 is being amortized on a straight-line basis through the end of the lease term in 2017 (approximately $31 million per year). The total above-market lease obligation of $457 million associated with the Bruce Mansfield Plant is being amortized on a straight-line basis through the end of 2016 (approximately $29 million per year). As of December 31, 2004 the above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant totaled approximately $728 million, of which $60 million is payable within one year.

The Company and TE refinanced high-cost fixed obligations related to their 1987 sale and leaseback transaction for the Bruce Mansfield Plant through a lower cost transaction in June and July 1997. In a June 1997 offering (Offering), the two companies pledged $720 million aggregate principal amount ($575 million for the Company and $145 million for TE) of FMB due through 2007 to a trust as security for the issuance of a like principal amount of secured notes due through 2007. The obligations of the two companies under these secured notes are joint and several. Using available cash, short-term borrowings and the net proceeds from the Offering, the two companies invested $906.5 million ($569.4 million for the Company and $337.1 million for TE) in a business trust, in June 1997. The trust used these funds in July 1997 to purchase lease notes and redeem all $873.2 million aggregate principal amount of 10-1/4% and 11-1/8% secured lease obligation bonds (SLOBs) due 2003 and 2016. The SLOBs were issued by a special-purpose-funding corporation in 1988 on behalf of lessors in the two companies' 1987 sale and leaseback transactions. The Shippingport arrangement effectively reduces lease costs related to that transaction (see Note 6 for FIN 46R discussion).

6.   VARIABLE INTEREST ENTITIES:

FIN 46R addresses the consolidation of VIEs, including special-purpose entities, that are not controlled through voting interests or in which the equity investors do not bear the residual economic risks and rewards. FirstEnergy adopted FIN 46R for special-purpose entities as of December 31, 2003 and for all other entities in the first quarter of 2004. The first step under FIN 46R is to determine whether an entity is within the scope of FIN 46R, which occurs if it is deemed to be a VIE. The Company consolidates VIEs when it is determined to be the primary beneficiary as defined by FIN 46R.

Included in the Company's consolidated financial statements is Shippingport, a VIE created in 1997, to refinance debt originally issued in connection with the Bruce Mansfield Plant sale and leaseback transaction.

Shippingport was established to purchase all of the SLOBs issued in connection with the Company's and TE's Bruce Mansfield Plant sale and leaseback transaction in 1987. The Company and TE used debt and available funds to purchase the notes issued by Shippingport. Shippingport's note payable to TE of $199 million ($10 million current) and $208 million ($9 million current) as of December 31, 2004 and December 31, 2003, respectively, is included in long-term debt on the Company's Consolidated Balance Sheets.

Through its investment in Shippingport, the Company has a variable interest in certain owner trusts that acquired the interests in the Bruce Mansfield Plant. The Company has concluded that it was not the primary beneficiary of the owner trusts and was therefore not required to consolidate these entities. The leases are accounted for as operating leases in accordance with GAAP.

The Company is exposed to losses under the sale-leaseback agreements upon the occurrence of certain contingent events that it considers unlikely to occur. The Company has 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 sale and leaseback agreement, the company has net minimum discounted lease payments of $115 million, that would not be payable if the casualty value payments are made.

7.   SALE OF GENERATING ASSETS:

In August 2002, FirstEnergy cancelled a November 2001 agreement to sell four coal-fired power plants (2,535 MW) to NRG Energy Inc. because NRG stated that it could not complete the transaction under the original terms of the agreement. NRG filed voluntary bankruptcy petitions in May 2003; subsequently, FirstEnergy reached an agreement for settlement of its claim against NRG. FirstEnergy sold its entire claim (including $32 million of cash proceeds received in December 2003) for $170 million (Company's share - $131 million) million in January 2004.

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8.   REGULATORY MATTERS:

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. With respect to each of these reliability enhancement initiatives, FirstEnergy submitted its response to the respective entity according to any required response dates. 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. Furthermore, FirstEnergy certified to NERC on June 30, 2004, with minor exceptions noted, that FirstEnergy had completed the recommended enhancements, policies, procedures and actions it had recommended be completed by June 30, 2004. In addition, FirstEnergy requested, and NERC provided, a technical assistance team of experts to assist in implementing and confirming timely and successful completion of various initiatives. The NERC-assembled independent verification team confirmed on July 14, 2004, that FirstEnergy had implemented the NERC Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts required to be completed by June 30, 2004, as well as NERC recommendations contained in the Control Area Readiness Audit Report required to be completed by summer 2004, and recommendations in the U.S. - Canada Power System Outage Task Force Report directed toward FirstEnergy and required to be completed by June 30, 2004, with minor exceptions noted by FirstEnergy. On December 28, 2004, FirstEnergy submitted a follow-up to its June 30, 2004 Certification and Report of Completion to NERC addressing the minor exceptions, which 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.

In October 2003, the Company filed an application for a Rate Stabilization Plan with the PUCO to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Company's transition plan market development period. On February 24, 2004, the Company filed a revised Rate Stabilization Plan to address PUCO concerns related to the original Rate Stabilization Plan. On June 9, 2004, the PUCO issued an order approving the revised Rate Stabilization Plan, subject to conducting a competitive bid process. On August 5, 2004, the Company accepted the Rate Stabilization Plan as modified and approved by the PUCO on August 4, 2004. In the second quarter of 2004, the Company 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 Company'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 cause the Company 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.

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On December 30, 2004, the Company 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. The Company 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. Various parties have intervened in these cases.

9.   CAPITALIZATION:

(A)   RETAINED EARNINGS-

There are no restrictions on retained earnings for payment of cash dividends on the Company’s common stock.

(B)   PREFERRED AND PREFERENCE STOCK-

The Company’s preferred stock may be redeemed in whole, or in part, with 30-90 days’ notice.

The preferred dividend rate on the Company’s Series L fluctuates based on prevailing interest rates and market conditions. The dividend rate for this issue was 7% in 2004.

The Company will exercise its option to redeem all outstanding shares of two series of preferred stock during the first quarter of 2005 as follows:

Series	Outstanding Shares		Call Price
$7.40A		500,000	$	101.00
L		474,000		100.00

The Company has three million authorized and unissued shares of preference stock having no par value.

(C) LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS-

The Company has a first mortgage indenture under which it issues FMB secured by a direct first mortgage lien on substantially all of its property and franchises, other than specifically excepted property. The Company has various debt covenants under its financing arrangements. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on debt which could trigger a default and the maintenance of minimum fixed charge ratios and debt to capitalization ratios covenants. There also exist cross-default provisions among financing agreements of FirstEnergy and the Company.

Sinking fund requirements for FMB and maturing long-term debt (excluding capital leases) for the next five years are:

	(In millions)
2005	$	75
2006		12
2007		129
2008		221
2009		163

Included in the table above are amounts for various variable interest rate long-term debt which have provisions by which individual debt holders have the option to "put back" or require the respective debt issuer to redeem their debt at those times when the interest rate may change prior to its maturity date. Those amounts are $75.2 million and $81.6 million in 2005 and 2008, respectively, representing the next time debt holders may exercise this provision.

The Company's obligations to repay certain pollution control revenue bonds are secured by several series of FMB. Certain pollution control revenue bonds are entitled to the benefit of an irrevocable bank LOC of $76 million and a noncancelable municipal bond insurance policy of $212 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the LOC or policies, the Company is entitled to a credit against its obligation to repay that bond. The Company pays annual fees of 1.375% to 1.625% of the amount of the LOC to the issuing bank and .21% to .30% of the amounts of the policies to the insurers and are obligated to reimburse the bank or insurers, as the case maybe, for any drawings thereunder.

The Company and TE have unsecured LOC of approximately $215.9 million in connection with the sale and leaseback of Beaver Valley Unit 2 that expire in April 2005. The Company and TE are jointly and severally liable for the LOC (see Note 5).

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(D)   SUBORDINATED DEBENTURES TO AFFILIATED TRUSTS-

As of December 31, 2004, the Company's wholly owned statutory business trust, Cleveland Electric Financing Trust, had $100 million of outstanding 9.00% preferred securities maturing in 2031. The sole assets of the trust are the Company's subordinated debentures with the same rate and maturity date as the preferred securities.

The Company formed the trust to sell preferred securities and invest the gross proceeds in the 9.00% subordinated debentures of the Company. The sole assets of the trust are the applicable subordinated debentures. Interest payment provisions of the subordinated debentures match the distribution payment provisions of the trust's preferred securities. In addition, upon redemption or payment at maturity of subordinated debentures, the trust's preferred securities will be redeemed on a pro rata basis at their liquidation value. Under certain circumstances, the applicable subordinated debentures could be distributed to the holders of the outstanding preferred securities of the trust in the event that the trust is liquidated. The Company has effectively provided a full and unconditional guarantee of payments due on the trust's preferred securities. The trust's preferred securities are redeemable at 100 percent of their principal amount at the Company's option beginning in December 2006. Interest on the subordinated debentures (and therefore distributions on the trust's preferred securities) may be deferred for up to 60 months, but the Company may not pay dividends on, or redeem or acquire, any of its cumulative preferred or common stock until deferred payments on its subordinated debentures are paid in full.

10.   ASSET RETIREMENT OBLIGATION:

In January 2003, the Company implemented SFAS 143, which provides accounting standards for retirement obligations associated with tangible long-lived assets. This statement requires recognition of the fair value of a liability for an ARO in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the ARO increases, resulting in a period expense. Upon retirement, a gain or loss would be recognized if the cost to settle the retirement obligation differs from the carrying amount.

The Company identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning, reclamation of a sludge disposal pond related to the Bruce Mansfield Plant, and closure of two coal ash disposal sites. The ARO liability as of the date of adoption of SFAS 143 was $238.3 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. Accretion during 2004 was $17 million, bringing the ARO liability as of December 31, 2004 to $272 million. The ARO includes the Company's obligation for nuclear decommissioning of the Beaver Valley Unit 2, Davis-Besse, and Perry generating facilities. The Company's share of the obligation to decommission these units was developed based on site specific studies performed by an independent engineer. The Company utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO. The Company maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of December 31, 2004, the fair value of the decommissioning trust assets was $383.9 million.

The following table provides the effect on income as if SFAS 143 had been applied during 2002.

Effect of the Change in Accounting
Principle Applied Retroactively	2002
	(In millions)
Reported net income	$	137
Increase (Decrease):
Elimination of decommissioning expense		29
Depreciation of asset retirement cost		(1	)
Accretion of ARO liability		(15	)
Non-regulated generation cost of removal component, net		9
Income tax effect		(9	)
Net earnings increase		13
Net income adjusted	$	150

The following table describes changes to the ARO balances during 2004 and 2003.

ARO Reconciliation	2004		2003
	(In millions)
Beginning balance as of January 1	$	255	$	238
Accretion		17		17
Ending balance as of December 31	$	272	$	255

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The following table provides the year-end balance of the ARO for 2002, as if SFAS 143 had been adopted on January 1, 2002.

Adjusted ARO Reconciliation	2002
	(In millions)
Beginning balance as of January 1	$	223
Accretion		15
Ending balance as of December 31	$	238

11.   SHORT-TERM BORROWINGS:

The Company may borrow from its affiliates on a short-term basis. As of December 31, 2004, the Company had total short-term borrowings of $488.6 million from its affiliates. The weighted average interest rates on short-term borrowings outstanding as of December 31, 2004 and 2003, were 2.1% and 2.2%, respectively.

12.   COMMITMENTS AND CONTINGENCIES:

(A)   NUCLEAR INSURANCE-

The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $10.8 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. Based on its ownership and leasehold interests in Beaver Valley Unit 2, the Davis-Besse Station and the Perry Plant, the Company's maximum potential assessment under the industry retrospective rating plan (assuming the other affiliate co-owners contribute their proportionate shares of any assessments under the retrospective rating plan) would be $121.4 million per incident but not more than $12.1 million in any one year for each incident.

The Company is also insured as to its respective interests in Beaver Valley Unit 2, Davis-Besse and Perry under policies issued to the operating company for each plant. Under these policies, up to $2.75 billion is provided for property damage and decontamination and decommissioning costs. The Company has also obtained approximately $478.9 million of insurance coverage for replacement power costs for its respective interests in Beaver Valley Unit 2, Davis-Besse and Perry. Under these policies, the Company can be assessed a maximum of approximately $20.9 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses.

The Company intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of the Company's plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by the Company's insurance policies, or to the extent such insurance becomes unavailable in the future, the Company would remain at risk for such costs.

(B)   ENVIRONMENTAL MATTERS-

Various federal, state and local authorities regulate the Company with regard to air and water quality and other environmental matters. The effects of compliance on the Company with regard to environmental matters could have a material adverse effect on the Company's earnings and competitive position. These environmental regulations affect the Company'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, the Company believes it is in material compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be. In accordance with the Ohio transition plan discussed in Note 8 - Regulatory Matters, generation operations and any related additional capital expenditures for environmental compliance are the responsibility of FirstEnergy's competitive services business unit.

Clean Air Act Compliance

The Company is required to meet federally approved SO₂ regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $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 Company cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

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The Company believes it is complying with SO₂ reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. 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 Company's facilities. The EPA's NO_x Transport Rule imposes uniform reductions of NO_x emissions (an approximate 85% reduction in utility plant NO_x emissions from projected 2007 emissions) across a region of nineteen states (including 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 Company believe its facilities are complying with the NO_x budgets established under State Implementation Plans (SIPs) 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 December 17, 2003, the EPA proposed the "Interstate Air Quality Rule" covering a total of 29 states (including Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air pollution emissions from 29 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. The EPA has proposed the Interstate Air Quality Rule to "cap-and-trade" NO_x and SO₂ emissions in two phases (Phase I in 2010 and Phase II in 2015). According to the EPA, SO₂ emissions would be reduced by approximately 3.6 million tons annually by 2010, across states covered by the rule, with reductions ultimately reaching more than 5.5 million tons annually. NO_x emission reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in 2015. The future cost of compliance with these proposed regulations may be substantial and will depend on whether and how they are ultimately implemented by the states in which the Company 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 December 15, 2003, the EPA proposed two different approaches to reduce mercury emissions from coal-fired power plants. The first approach would require plants to install controls known as MACT based on the type of coal burned. According to the EPA, if implemented, the MACT proposal would reduce nationwide mercury emissions from coal-fired power plants by 14 tons to approximately 34 tons per year. The second approach proposes a cap-and-trade program that would reduce mercury emissions in two distinct phases. Initially, mercury emissions would be reduced by 2010 as a "co-benefit" from implementation of SO₂ and NO_x emission caps under the EPA's proposed Interstate Air Quality Rule. Phase II of the mercury cap-and-trade program would be implemented in 2018 to cap nationwide mercury emissions from coal-fired power plants at 15 tons per year. The EPA has agreed to choose between these two options and issue a final rule by March 15, 2005. The future cost of compliance with these regulations may be substantial.

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 Company 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 December 31, 2004, based on estimates of the total costs of cleanup, the Company's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. Included in Current Liabilities and Other Noncurrent Liabilities are accrued liabilities aggregating approximately $2.4 million as of December 31, 2004. The Company 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 the Company's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

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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% through 2012.

The Company 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 Company is lower than many regional competitors due to the Company's diversified generation sources which includes low or non-CO₂ emitting gas-fired and nuclear generators.

Clean Water Act

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

On September 7, 2004, the EPA established new performance standards under Clean Water Act Section 316(b) 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 Company is 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. The Company 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.

(C) OTHER LEGAL PROCEEDINGS-

Power Outages and Related Litigation

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. On April 5, 2004, the U.S. - Canada Power System Outage Task Force released its final report on the outages. In the final report, the Task Force 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 contains 46 årecommendations to prevent or minimize the scope of future blackouts.æ Forty-five of those recommendations relate to broad industry or policy matters while one, including subparts, relates to activities the Task Force recommends 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 are consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy certified to NERC on June 30, 2004, completion of various reliability recommendations and further received independent verification of completion status from a NERC verification team on July 14, 2004 with minor exceptions noted by FirstEnergy (see Note 8). 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 undertaken during 2004 will have a material effect on its operations or financial results. FirstEnergy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. FirstEnergy has not accrued a liability as of December 31, 2004 for any expenditures in excess of those actually incurred through that date.

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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 at the PUCO. The other two cases were appealed. One case was dismissed and no further appeal was sought. The remaining case is pending. 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 has been filed 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 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 relating to the Davis-Besse Nuclear Power Station outage 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. In addition, FENOC remains subject to possible civil enforcement action by the NRC in connection with the events leading to the Davis-Besse outage in 2002.

On August 12, 2004, the NRC notified FENOC that it will 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 Company has a 44.85% interest. Although the NRC noted that the plant continues to operate safely, the agency has indicated that its increased oversight will include an extensive NRC team inspection to assess the equipment problems and the sufficiency of FENOC's corrective actions. The outcome of these matters could include NRC enforcement action or other impacts on operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition.

Other Legal Matters

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

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 Company, 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.

On September 16, 2004, the FERC issued an order that imposed additional obligations on the Company under certain pre-Open Access transmission contracts among the Company and the cities of Cleveland and Painesville. Under the FERC’s decision, the Company may be responsible for a portion of new energy market charges imposed by MISO when its energy markets begin in the spring of 2005. The Company filed for rehearing of the order from the FERC on October 18, 2004. The impact of the FERC decision on the Company is dependent upon many factors, including the arrangements made by the cities for transmission service, the startup date for the MISO energy market, and the resolution of the rehearing request, and cannot be determined at this time.

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

13.   NEW ACCOUNTING STANDARDS AND INTERPRETATIONS:

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. The Company is currently evaluating this standard but does not expect it to have a material impact on the financial statements.

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 the Company after June 30, 2005. The Company 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, the Company will continue to evaluate its investments as required by existing authoritative guidance.

EITF Issue No. 03-16, "Accounting for Investments in Limited Liability Companies"

In March 2004, the FASB ratified the final consensus on Issue 03-16. EITF 03-16 requires that an investment in a limited liability company that maintains a "specific ownership account" for each investor should be viewed as similar to an investment in a limited partnership for determining whether the cost or equity method of accounting should be used. The equity method of accounting is generally required for investments that represent more than a three to five percent interest in a limited partnership. EITF 03-16 was adopted by CEI in the third quarter of 2004 and did not affect the Company's financial statements.

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.

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FSP 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003"

Issued in May 2004, FSP 106-2 provides guidance on accounting for the effects of the Medicare Act for employers that sponsor postretirement health care plans that provide prescription drug benefits. FSP 106-2 also requires certain disclosures regarding the effect of the federal subsidy provided by the Medicare Act. The effect of the federal subsidy provided under the Medicare Act on the Company's consolidated financial statements is described in Note 3.

14.   SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):

The following summarizes certain consolidated operating results by quarter for 2004 and 2003.

	March 31,		June 30,		September 30,		December 31,
Three Months Ended	2004		2004		2004		2004
	(In millions)
Operating Revenues	$	426.5	$	440.9	$	504.9	$	436.2
Operating Expenses and Taxes		353.2		363.5		402.5		361.4
Operating Income		73.3		77.4		102.4		74.8
Other Income		11.7		9.5		8.3		12.7
Net Interest Charges		36.6		37.1		28.3		31.6
Net Income	$	48.4	$	49.8	$	82.4	$	55.9
Earnings on Common Stock	$	46.7	$	48.0	$	80.7	$	54.1

	March 31,		June 30,		September 30,		December 31,
Three Months Ended	2003		2003		2003		2003
	(In millions)
Operating Revenues	$	419.8	$	412.1	$	496.1	$	391.7
Operating Expenses and Taxes		365.8		367.6		395.9		334.9
Operating Income		54.0		44.5		100.2		56.8
Other Income		4.7		4.7		6.2		81.7
Net Interest Charges		43.5		39.9		38.6		33.9
Income Before Cumulative Effect of Accounting Change		15.2		9.3		67.8		104.6
Cumulative Effect of Accounting Change (Net of Income Taxes)		42.4		--		--		--
Net Income	$	57.6	$	9.3	$	67.8	$	104.6
Earnings on Common Stock	$	58.4	$	7.5	$	66.0	$	100.0

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