THE TOLEDO EDISON COMPANY

2004 ANNUAL REPORT TO STOCKHOLDERS

The Toledo Edison Company (TE) 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 2,500 square miles in northwestern Ohio. The area it serves has a population of approximately 0.8 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	4-16
Consolidated Statements of Income	17
Consolidated Balance Sheets	18
Consolidated Statements of Capitalization	19
Consolidated Statements of Common Stockholder's Equity	20
Consolidated Statements of Preferred Stock	20
Consolidated Statements of Cash Flows	21
Consolidated Statements of Taxes	22
Notes to Consolidated Financial Statements	23-43

GLOSSARY OF TERMS

The following abbreviations and acronyms are used in this report to identify The Toledo Edison Company and its affiliates:

ATSI	American Transmission Systems, Inc., owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an affiliated Ohio electric utility
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
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
TECC	Toledo Edison Capital Corporation, a 90% owned subsidiary of TE
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

i

GLOSSARY OF TERMS Cont.

NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Council
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"
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 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 Report 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 Toledo Edison Company:

We have completed an integrated audit of The Toledo Edison 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 Toledo Edison Company and its subsidiary 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 TOLEDO EDISON COMPANY

SELECTED FINANCIAL DATA

	2004			2003			2002			2001			2000
	(Dollars in thousands)
GENERAL FINANCIAL INFORMATION:
Operating Revenues	$	1,008,112		$	932,335		$	996,045		$	1,086,503		$	954,947
Operating Income	$	93,075		$	35,660		$	36,699		$	85,964		$	194,325
Income (Loss) Before Cumulative Effect of Accounting Change	$	86,283		$	19,930		$	(5,142	)	$	42,691		$	138,144
Net Income (Loss)	$	86,283		$	45,480		$	(5,142	)	$	42,691		$	138,144
Earnings (Loss) on Common Stock	$	77,439		$	36,642		$	(15,898	)	$	26,556		$	121,897
Total Assets	$	2,833,906		$	2,855,398		$	2,861,614		$	2,875,908		$	3,010,657
CAPITALIZATION AS OF DECEMBER 31:
Common Stockholder’s Equity	$	835,327		$	749,521		$	681,195		$	629,805		$	610,847
Preferred Stock Not Subject to Mandatory Redemption		126,000			126,000			126,000			126,000			210,000
Long-Term Debt		300,299			270,072			557,265			646,174			944,193
Total Capitalization	$	1,261,626		$	1,145,593		$	1,364,460		$	1,401,979		$	1,765,040
CAPITALIZATION RATIOS AS OF DECEMBER 31:
Common Stockholder’s Equity		66.2	%		65.4	%		49.9	%		44.6	%		34.6	%
Preferred Stock Not Subject to Mandatory Redemption		10.0			11.0			9.2			9.0			11.9
Long-Term Debt		23.8			23.6			40.9			46.4			53.5
Total Capitalization		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%
DISTRIBUTION KWH DELIVERIES (Millions)
Residential		2,316			2,312			2,427			2,258			2,183
Commercial		2,796			2,771			2,702			2,667			2,380
Industrial		5,006			5,097			5,280			5,397			5,595
Other		56			69			57			61			49
Total		10,174			10,249			10,466			10,383			10,207
CUSTOMERS SERVED:
Residential		273,800			270,258			272,474			270,589			269,071
Commercial		36,710			36,969			32,037			31,680			31,413
Industrial		211			215			1,883			1,898			1,917
Other		504			451			468			443			598
Total		311,225			307,893			306,862			304,610			302,999
Number of Employees		414			446			508			507			539

3

THE TOLEDO EDISON 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 increased to $77 million in 2004 from $37 million in 2003. Earnings on common stock in 2003 included an after-tax gain of $26 million from the cumulative effect of an accounting change due to the adoption of SFAS 143. Income before the cumulative effect increased to $86 million from $20 million in 2003. This increase resulted primarily from the restart of the Davis-Besse Nuclear Power Station in April 2004 that contributed to higher operating revenues and lower nuclear operating costs; interest charges were also lower in 2004. These factors were partially offset by higher fuel and purchased power costs, other operating costs and depreciation and amortization costs.

Earnings on common stock increased to $37 million in 2003 from a loss of $16 million in 2002. Income before the cumulative effect of an accounting change was $20 million in 2003, compared to a loss of $5 million in 2002. The increase in 2003 reflected lower fuel and purchased power costs, other operating costs, depreciation and financing costs and net proceeds of $12 million (pre-tax) from the settlement of our claim against NRG Energy, Inc. (see Note 7), partially offset by lower operating revenues, higher nuclear operating costs and amortization of regulatory assets.

Operating revenues increased by $76 million or 8.1% in 2004 from 2003. The increase in revenues resulted principally from a $98 million (69.0%) increase in wholesale sales (primarily to FES) due to increased nuclear generation available for sale, partially offset by a $6 million decrease in retail generation sales revenues from franchise customers and $5 million of shopping incentive credits discussed below. Reduced retail generation revenues (residential and commercial - $4 million and $5 million, respectively) in 2004 reflected increases in electric generation services to residential and commercial customers provided by alternative suppliers as a percent of total sales deliveries in TE’s franchise area of 6.9 percentage points and 2.5 percentage points, respectively, while shopping by industrial customers decreased slightly. Increased industrial customer generation revenue of $3 million was due to higher unit prices offsetting a 1.5% decrease in KWH sales.

Revenues from distribution throughput decreased by $7 million in 2004 compared to 2003, primarily as a result of lower unit prices in all customer sectors. Distribution deliveries to the aggregate industrial and commercial sector decreased and deliveries to residential customers were nearly unchanged in 2004 as compared to 2003.

4

Operating revenues decreased by $64 million or 6.4% in 2003 from 2002. Reduced revenues resulted from lower KWH sales due to milder weather in the second and third quarters, continued sluggishness in the regional economy and increased sales by alternative suppliers. KWH sales to retail customers in all customer sectors (residential, commercial and industrial) declined by 9.0% in 2003 from 2002, reducing generation retail sales revenues by $49.8 million. Electric generation services provided to retail customers by alternative suppliers as a percent of total sales delivered in our service area increased 5.9 percentage points in 2003. Sales revenues from wholesale customers decreased by $19 million in 2003 compared to 2002. KWH sales to the wholesale market declined in 2003 due to reduced nuclear generation available for sale to FES. Available generation decreased due to the extended outage at Davis-Besse and additional nuclear refueling activities in 2003 compared to 2002. Distribution deliveries decreased 2.1% in 2003 from 2002. However, higher unit prices resulted in overall revenue increases from electricity throughput of $17.2 million when compared to 2002.

Under the Ohio transition plan, we provide incentives to customers to encourage switching to alternative energy providers - $5 million of additional credits in 2004, compared with 2003; and $7 million of additional credits in 2003, compared to 2002. These revenue reductions are deferred for future recovery under our transition plan and do not affect current period earnings.

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

Changes in KWH Sales	2004			2003
Increase (Decrease)
Electric Generation:
Retail		(3.8	)%		(9.0	)%
Wholesale		69.0	%		(15.4	)%
Total Electric Generation Sales		26.2	%		(11.8	)%
Distribution Deliveries:
Residential		0.2	%		(4.8	)%
Commercial and industrial		(0.8	)%		(1.4	)%
Total Distribution Deliveries		(0.7	)%		(2.1	)%

Operating Expenses and Taxes

Total operating expenses and taxes increased by $18 million in 2004 and decreased by $63 million in 2003. The following table presents changes from the prior year by expense category.

Operating Expenses and Taxes - Changes	2004			2003
Increase (Decrease)	(In millions)
Fuel costs	$	18		$	(6	)
Purchased power costs		12			(27	)
Nuclear operating costs		(87	)		2
Other operating costs		27			(16	)
Provision for depreciation		4			(28	)
Amortization of regulatory assets		10			9
Deferral of new regulatory assets		(11	)		(3	)
General taxes		3			(2	)
Income taxes		42			8
Total operating expenses and taxes	$	18		$	(63	)

Higher fuel costs in 2004, compared with 2003, resulted principally from increased nuclear generation, which was up 109.4%. Purchased power costs increased in 2004, compared with 2003, due to higher unit costs partially offset by lower KWH purchased due to lower retail generation sales requirements. Decreased nuclear operating costs in 2004 were due to reduced incremental costs associated with the extended Davis-Besse outage, unplanned work performed during the Perry Plant's 56-day nuclear refueling outage in 2003 and the 28-day refueling outage at Beaver Valley Unit 2 in 2003. Other operating costs increased in 2004, compared to 2003, reflecting higher employee benefits costs - specifically an increase in health care costs.

5

Lower fuel and purchased power costs in 2003, compared with 2002, resulted from reduced nuclear generation - down 19.9%, and reduced KWH required for customer needs which more than offset an increase in unit costs. Increased nuclear costs resulted from incremental costs associated with the extended Davis-Besse outage, the Perry Plant's nuclear refueling outage and the refueling outage at Beaver Valley Unit 2 in 2003, compared with a 24-day refueling outage at Beaver Valley Unit 2, in the first quarter of 2002. A decrease in other operating costs in 2003 reflect lower employee costs - specifically the absence of short-term incentive compensation and reduced health care costs.

Depreciation charges increased by $4 million in 2004 compared to 2003 due to a higher level of depreciable property in 2004. Charges for depreciation decreased by $28 million in 2003, compared with 2002, primarily due to revised service life assumptions for nuclear generating plants and lower charges resulting from the implementation of SFAS 143 ($15 million). The increase in charges for amortization of regulatory assets in 2004 and 2003, compared to the prior years, reflected increases in transition costs amortization. The higher deferrals of new regulatory assets in 2004 and 2003 compared to the prior year were due to higher shopping incentives ($5 million) and deferred interest on the shopping incentives ($6 million) in 2004 and higher shopping incentive deferrals ($7 million) partially offset by lower tax related deferrals ($4 million) in 2003.

General taxes increased $3 million in 2004 primarily due to the absence of settled property tax claims in 2003 and correspondingly decreased $2 million in 2003 due to settled property tax claims.

Other Income

Other Income increased by $2 million in 2004, compared to 2003, due to $16 million of interest income from Shippingport Capital Trust (see Note 6 - Variable Interest Entities) beginning in 2004 partially offset by the absence of the $12 million NRG settlement in 2003. Other income increased in 2003 from 2002 reflecting the 2003 NRG settlement.

Net Interest Charges

Net interest charges continued to trend lower, decreasing by $7 million in 2004 and $19 million in 2003, compared to the prior year, reflecting redemptions and refinancing since 2003. We redeemed $230 million of long-term debt and repriced $121 million of pollution control notes during 2004.

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 $26 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 $44 million increase to income, or $26 million net of income taxes.

Capital Resources and Liquidity

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

Changes in Cash Position

As of December 31, 2004, we had $15,000 of cash and cash equivalents, compared with $2 million as of December 31, 2003. The major sources for changes in these balances are summarized below.

6

Cash Flows From Operating Activities

Net cash provided from operating activities was $183 million in 2004, $61 million in 2003 and $166 million in 2002, summarized as follows:

Operating Cash Flows	2004			2003			2002
	(In millions)
Cash earnings (1)	$	240		$	119		$	61
Pension trust contribution(2)		(8	)		--			--
Working capital and other		(49	)		(58	)		105
Total	$	183		$	61		$	166

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

⁽²⁾ Pension trust contribution net of $5 million of income tax benefits.

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)	$	86		$	45		$	(5	)
Non-Cash Charges (Credits):
Provision for depreciation		58			55			82
Amortization of regulatory assets		124			114			105
Nuclear fuel and capital lease amortization		25			9			12
Deferral of new regulatory assets		(39	)		(28	)		(25	)
Deferred operating lease costs, net		(23	)		(37	)		(25	)
Accrued retirement benefits obligation		6			6			(59	)
Accrued compensation		1			(5	)		3
Deferred income taxes and investment tax credits, net		2			4			(27	)
Cumulative effect of accounting change		--			(44	)		--
Cash earnings (Non-GAAP)	$	240		$	119		$	61

Net cash provided from operating activities increased $122 million in 2004 from 2003 as a result of a $121 million increase in cash earnings as described above under "Results of Operations" and a $9 million increase from changes in working capital. These increases were partially offset by a $8 million after-tax voluntary pension trust contribution.

Net cash provided from operating activities decreased $105 million in 2003 from 2002 as a result of a $163 million decrease in working capital partially offset by a $58 million increase in cash earnings as described under "Results of Operations". The largest factor contributing to the change in working capital was a $95 million comparative change in accounts payable.

Cash Flows From Financing Activities

Net cash used for financing activities increased by $101 million in 2004 from 2003 and decreased by $36 million in 2003 from 2002.

7

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	$	104	$	--	$	20
Redemptions
Unsecured Notes	$	--	$	7	$	135
Secured Notes		261		183		44
Preferred Stock		--		--		85
Other, principally redemption premiums		1		1		2
	$	262	$	191	$	266
Short-term Borrowings, Net	$	74	$	206	$	132

As of December 31, 2004, we had $136 million of cash and temporary investments (which include short-term notes receivable from associated companies) and $430 million of short-term indebtedness. We 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 $998 million of additional FMB on the basis of property additions and retired bonds under the terms of our mortgage indenture. Based upon applicable earnings coverage tests, we could issue up to $736 million of preferred stock (assuming no additional debt was issued as of December 31, 2004).

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, 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 on all securities is stable.

Ratings of Securities
	Securities	S&P	Moody’s	Fitch
FirstEnergy	Senior unsecured	BB+	Baa3	BBB-
TE	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 to $91 million in 2004 from $86 million in 2003. This increase was primarily due to the change in the investment in lessor notes, partially offset by lower property additions.

8

Our capital spending for the period 2005-2007 is expected to be about $192 million (excluding nuclear fuel), of which approximately $56 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to be approximately $54 million, of which about $8 million applies to 2005. During the same period, our nuclear fuel investments are expected to be reduced by approximately $64 million and $20 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 were as follows:

					2006-		2008-
Contractual Obligations	Total		2005		2007		2009		Thereafter
	(In millions)
Long-term debt (3)	$	383	$	--	$	30	$	--	$	353
Short-term borrowings		430		430		--		--		--
Operating leases(1)		918		79		158		145		536
Purchases (2)		264		38		96		81		49
Total	$	1,995	$	547	$	284	$	226	$	938

(1)  Operating lease payments are net of capital trust receipts of $302.2 million (see Note 5).

⁽²⁾   Fuel and power purchases under contracts with fixed or minimum quantities and approximate timing.

⁽³⁾   Amounts reflected to not include interest on long-term debt. 

Off-Balance Sheet Arrangements

Obligations not included on our Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley Unit 2, which are 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 $570 million.

We sell substantially all of our retail customer receivables to CFC, a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust (a "qualified special purpose entity" under SFAS 140) under an asset-backed securitization agreement. This arrangement provided $29 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 and debt obligations.

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	$	134		$	12		$	9		$	15		$	12		$	289		$	471		$	515
Average interest rate		7.8	%		7.7	%		7.7	%		7.7	%		7.7	%		6.6	%		7.1	%
Liabilities
Long-term Debt and Other
Long-Term Obligations:
Fixed rate							$	30								$	113		$	143		$	150
Average interest rate								7.1									7.5	%		7.4	%
Variable rate																$	240		$	240		$	240
Average interest rate																	2.2	%		2.2	%
Short-term Borrowings	$	430																	$	430		$	430
Average interest rate		2.0	%																	2.0	%

9

Equity Price Risk

Included in our nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $188 million and $145 million as of December 31, 2004 and 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $19 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 PLR responsibility to our franchise customers through December 31, 2005.

Regulatory assets are costs which have been authorized by the PUCO and the FERC for recovery from customers in future periods 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 31, 2004 and 2003 were $375 million and $459 million, respectively. All of our 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 160 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 cost 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 mid-2007 to as late as mid-2008;

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

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

On December 9, 2004, the PUCO rejected the auction price results from a required competitive bid process and issued an entry stating that the pricing under the approved revised Rate Stabilization Plan will take effect on January 1, 2006. The PUCO may 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.

10

On December 30, 2004, we filed an application with the PUCO seeking tariff adjustments to recover increases of approximately $0.1 million in transmission and ancillary service costs beginning January 1, 2006. 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.

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 (see Note 12(B) - Environmental Matters). We continue to evaluate our compliance plans and other compliance options.

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 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" NOx 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.

11

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 $0.2 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.

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.

12

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.

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 19.91% 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-

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to our normal business operations 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 TE, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a second subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.

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.

13

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.

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 the 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 $13 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 $11 million. As prescribed by SFAS 87, we reduced our additional minimum liability by $1 million, recording an increase in an intangible asset of $1 million and increasing OCI by $2 million. The balance in AOCL of $8 million (net of $6 million in deferred taxes) will reverse in future periods to the extent the fair value of trust assets exceeds the accumulated benefit obligation.

14

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 our health care plans, and projections of future medical trend rates.

Ohio Transition Cost Amortization

In connection with our initial Ohio transition 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.

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 $505 million of goodwill.

Nuclear Decommissioning

In accordance with SFAS No. 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.

15

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, the Company will continue to evaluate its investments as required by existing authoritative guidance.

16

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31,	2004			2003			2002
	(In thousands)
OPERATING REVENUES (a) (Note 2(I))	$	1,008,112		$	932,335		$	996,045
OPERATING EXPENSES AND TAXES:
Fuel and purchased power (Note 2(I))		363,759			333,539			366,932
Nuclear operating costs		168,401			254,986			252,608
Other operating costs (Note 2(I))		152,879			125,869			141,997
Provision for depreciation		57,948			54,524			82,316
Amortization of regulatory assets		123,858			113,664			104,300
Deferral of new regulatory assets		(38,696	)		(27,575	)		(24,534	)
General taxes		54,142			50,742			53,223
Income taxes (benefit)		32,746			(9,074	)		(17,496	)
Total operating expenses and taxes		915,037			896,675			959,346
OPERATING INCOME		93,075			35,660			36,699
OTHER INCOME (NET OF INCOME TAXES) (Notes 2(I) and 7)		22,951			20,558			13,329
NET INTEREST CHARGES:
Interest on long-term debt		27,153			38,874			58,120
Allowance for borrowed funds used during construction and capitalized interest		(3,696	)		(5,838	)		(2,502	)
Other interest expense (credit)		6,286			3,252			(448	)
Net interest charges		29,743			36,288			55,170
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE		86,283			19,930			(5,142	)
Cumulative effect of accounting change (net of income taxes of $18,201,000) (Note 2(G))		--			25,550			--
NET INCOME (LOSS)		86,283			45,480			(5,142	)
PREFERRED STOCK DIVIDEND REQUIREMENTS		8,844			8,838			10,756
EARNINGS (LOSS) ON COMMON STOCK	$	77,439		$	36,642		$	(15,898	)

(a) Includes electric sales to associated companies of $305 million, $212 million and $232 million in 2004, 2003 and 2002, respectively.

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

17

THE TOLEDO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS

As of December 31,	2004		2003
ASSETS	(In thousands)
UTILITY PLANT:
In service	$	1,856,478	$	1,714,870
Less-Accumulated provision for depreciation		778,864		721,754
		1,077,614		993,116
Construction work in progress-
Electric plant		58,535		125,051
Nuclear fuel		15,998		20,189
		74,533		145,240
		1,152,147		1,138,356
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes (Note 5)		190,692		200,938
Nuclear plant decommissioning trusts		297,803		240,634
Long-term notes receivable from associated companies		39,975		163,626
Other		2,031		2,119
		530,501		607,317
CURRENT ASSETS:
Cash and cash equivalents		15		2,237
Receivables-
Customers		4,858		4,083
Associated companies		36,570		29,158
Other		3,842		14,386
Notes receivable from associated companies		135,683		19,316
Materials and supplies, at average cost		40,280		35,147
Prepayments and other		1,150		6,704
		222,398		111,031
DEFERRED CHARGES:
Regulatory assets		374,814		459,040
Goodwill		504,522		504,522
Property taxes		24,100		24,443
Other		25,424		10,689
		928,860		998,694
	$	2,833,906	$	2,855,398
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder’s equity	$	835,327	$	749,521
Preferred stock not subject to mandatory redemption		126,000		126,000
Long-term debt		300,299		270,072
		1,261,626		1,145,593
CURRENT LIABILITIES:
Currently payable long-term debt		90,950		283,650
Short-term borrowings		--		70,000
Accounts payable-
Associated companies		110,047		132,876
Other		2,247		2,816
Notes payable to associated companies		429,517		285,953
Accrued taxes		46,957		55,604
Lease market valuation liability		24,600		24,600
Other		53,055		49,711
		757,373		905,210
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		221,950		201,954
Accumulated deferred investment tax credits		25,102		27,200
Retirement benefits		39,227		47,006
Asset retirement obligation		194,315		181,839
Lease market valuation liability		268,000		292,600
Other		66,313		53,996
		814,907		804,595
COMMITMENTS AND CONTINGENCIES
(Notes 5 and 12)
	$	2,833,906	$	2,855,398

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

18

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

As of December 31,	2004		2003
(Dollars in thousands, except per share amounts)
COMMON STOCKHOLDER'S EQUITY:
Common stock, $5 par value, authorized 60,000,000 shares 39,133,887 shares outstanding	$	195,670	$	195,670
Other paid-in capital		428,559		428,559
Accumulated other comprehensive income (Note 2(F))		20,039		11,672
Retained earnings (Note 9(A))		191,059		113,620
Total common stockholder's equity		835,327		749,521

	Number of Shares Outstanding				Optional Redemption Prices
	2004		2003		Per Share		Aggregate
PREFERRED STOCK NOT SUBJECT TO
MANDATORY REDEMPTION (Note 9(B)):
Cumulative, $100 par value-
Authorized 3,000,000 shares
$4.25		160,000		160,000	$	104.63	$	16,740	16,000	16,000
$4.56		50,000		50,000		101.00		5,050	5,000	5,000
$4.25		100,000		100,000		102.00		10,200	10,000	10,000
		310,000		310,000				31,990	31,000	31,000
Cumulative, $25 par value-
Authorized 12,000,000 shares
$2.365		1,400,000		1,400,000		27.75		38,850	35,000	35,000
Adjustable Series A		1,200,000		1,200,000		25.00		30,000	30,000	30,000
Adjustable Series B		1,200,000		1,200,000		25.00		30,000	30,000	30,000
		3,800,000		3,800,000				98,850	95,000	95,000
Total		4,110,000		4,110,000			$	130,840	126,000	126,000

LONG-TERM DEBT (Note 9(C)):
First mortgage bonds:
7.875% due 2004		--			145,000
Total first mortgage bonds		--			145,000
Unsecured notes:
*  1.980% due 2030		34,850			34,850
*  4.500% due 2033		31,600			31,600
*  2.000% due 2033		18,800			18,800
*  3.100% due 2033		5,700			--
Total unsecured notes		90,950			85,250
Secured notes:
7.670% due 2004		--			70,000
7.130% due 2007		30,000			30,000
7.625% due 2020		45,000			45,000
7.750% due 2020		54,000			54,000
9.220% due 2021		--			15,000
8.000% due 2023		--			30,500
* 1.750% due 2024		67,300			--
6.100% due 2027		10,100			10,100
5.375% due 2028		3,751			3,751
* 1.690% due 2033		30,900			30,900
* 1.800% due 2033		20,200			20,200
* 1.750% due 2033		30,500			--
Total secured notes		291,751			309,451
Net unamortized premium on debt		8,548			14,021
Long-term debt due within one year		(90,950	)		(283,650	)
Total long-term debt		300,299			270,072
TOTAL CAPITALIZATION	$	1,261,626		$	1,145,593

* 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.

19

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

										Accumulated
								Other		Other
	Comprehensive			Number		Par		Paid-In		Comprehensive			Retained
	Income (Loss)			of Shares		Value		Capital		Income (Loss)			Earnings
	(Dollars in thousands)
Balance, January 1, 2002				39,133,887		$195,670		$328,559		$ 7,100			$ 98,476
Net loss	$	(5,142	)											(5,142	)
Unrealized loss on investments, net of (4,034,000) of     income taxes		(5,997	)								(5,997	)
Minimum liability for unfunded retirement benefits, net of     $(15,042,000) of income taxes.		(21,115	)								(21,115	)
Comprehensive loss	$	(32,254	)
Equity contribution from parent									100,000
Cash dividends on preferred stock														(9,457	)
Cash dividends on common stock														(5,600	)
Preferred stock redemption premiums														(1,299	)
Balance, December 31, 2002					39,133,887		195,670		428,559		(20,012	)		76,978
Net income	$	45,480												45,480
Unrealized gain on investments, net of $13,908,000 of     income taxes		19,988									19,988
Minimum liability for unfunded retirement benefits, net of    $8,489,000 of income taxes.		11,696									11,696
Comprehensive income	$	77,164
Cash dividends on preferred stock														(8,838	)
Balance, December 31, 2003					39,133,887		195,670		428,559		11,672			113,620
Net income	$	86,283												86,283
Unrealized gain on investments, net of $5,246,000 of    income taxes		7,253									7,253
Minimum liability for unfunded retirement benefits, net of    $717,000 of income taxes.		1,114									1,114
Comprehensive income	$	94,650
Cash dividends on preferred stock														(8,844	)
Balance, December 31, 2004					39,133,887	$	195,670	$	428,559	$	20,039		$	191,059

CONSOLIDATED STATEMENTS OF PREFERRED STOCK

	Not Subject to Mandatory Redemption
	Number			Carrying
	of Shares			Value
	(Dollars in thousands)
Balance, January 1, 2002		5,700,000		$	210,000
Redemptions
$8.32 Series		(100,000	)		(10,000	)
$7.76 Series		(150,000	)		(15,000	)
$7.80 Series		(150,000	)		(15,000	)
$10.00 Series		(190,000	)		(19,000	)
$2.21 Series		(1,000,000	)		(25,000	)
Balance, December 31, 2002		4,110,000			126,000
Balance, December 31, 2003		4,110,000			126,000
Balance, December 31, 2004		4,110,000		$	126,000

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

20

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31,	2004			2003			2002
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$	86,283		$	45,480		$	(5,142	)
Adjustments to reconcile net income (loss) to net cash from operating activities:
Provision for depreciation		57,948			54,524			82,316
Amortization of regulatory assets		123,858			113,664			104,300
Deferral of new regulatory assets		(38,696	)		(27,575	)		(24,534	)
Nuclear fuel and capital lease amortization		25,034			9,289			11,866
Deferred rents and lease market valuation liability		(23,121	)		(37,001	)		(24,600	)
Deferred income taxes and investment tax credits, net		6,123			3,563			(26,672	)
Accrued retirement benefit obligation		5,889			6,205			(59,123	)
Accrued compensation, net		1,074			(5,365	)		2,614
Cumulative effect of accounting change (Note 2(G))		--			(43,751	)		--
Pension trust contribution		(12,572	)		--			--
Decrease (increase) in operating assets:
Receivables		10,228			19,107			5,164
Materials and supplies		(5,133	)		1,481			(5,582	)
Prepayments and other current assets		5,554			(3,249	)		11,125
Increase (decrease) in operating liabilities:
Accounts payable		(23,398	)		(53,765	)		40,801
Accrued taxes		(8,647	)		20,928			(4,881	)
Accrued interest		(9,080	)		(3,965	)		(3,541	)
Other		(18,438	)		(38,977	)		61,538
Net cash provided from operating activities		182,906			60,593			165,649
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		103,500			--			19,580
Short-term borrowings, net		73,565			206,300			132,445
Equity contributions from parent		--			--			100,000
Redemptions and Repayments-
Preferred stock		--			--			(85,299	)
Long-term debt		(262,162	)		(190,794	)		(180,368	)
Dividend Payments-
Common stock		--			--			(5,600	)
Preferred stock		(8,844	)		(8,844	)		(10,057	)
Net cash provided from (used for) financing activities		(93,941	)		6,662			(29,299	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(64,629	)		(84,924	)		(105,510	)
Loan repayments from (payments to) associated companies, net		7,284			(18,826	)		5,838
Investment in lessor notes (Note 5)		10,246			40,025			21,168
Contributions to nuclear decommissioning trust		(28,541	)		(28,541	)		(28,541	)
Other		(15,547	)		6,560			(8,919	)
Net cash used for investing activities		(91,187	)		(85,706	)		(115,964	)
Net increase (decrease) in cash and cash equivalents		(2,222	)		(18,451	)		20,386
Cash and cash equivalents at beginning of period		2,237			20,688			302
Cash and cash equivalents at end of period	$	15		$	2,237		$	20,688
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	40,082		$	38,576		$	61,498
Income taxes (refund)	$	53,728		$	(9,257	)	$	3,561

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

21

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF TAXES

For the Years Ended December 31,	2004			2003			2002
	(In thousands)
GENERAL TAXES:
Ohio kilowatt-hour excise*	$	28,158		$	29,793		$	28,046
Real and personal property		23,559			18,488			22,737
Social security and unemployment		2,089			1,861			1,684
Other		336			600			756
Total general taxes	$	54,142		$	50,742		$	53,223
PROVISION FOR INCOME TAXES:
Currently payable-
Federal	$	34,587		$	15,495		$	12,845
State		11,640			4,537			3,983
		46,227			20,032			16,828
Deferred, net-
Federal		7,156			4,414			(19,091	)
State		1,064			1,205			(5,570	)
		8,220			5,619			(24,661	)
Investment tax credit amortization		(2,097	)		(2,056	)		(2,011	)
Total provision for (benefit from) income taxes	$	52,350		$	23,595		$	(9,844	)
INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income	$	32,746		$	(9,074	)	$	(17,496	)
Other income		19,604			14,468			7,652
Cumulative effect of accounting change		--			18,201			--
Total provision for (benefit from) income taxes	$	52,350		$	23,595		$	(9,844	)
RECONCILIATION OF FEDERAL INCOME TAX
EXPENSE AT STATUTORY RATE TO TOTAL
PROVISION FOR INCOME TAXES:
Book income before provision for income taxes	$	138,633		$	69,075		$	(14,986	)
Federal income tax expense at statutory rate	$	48,522		$	24,176		$	(5,245	)
Increases (reductions) in taxes resulting from-
State income taxes, net of federal income tax benefit		8,258			3,732			(1,031	)
Amortization of investment tax credits		(2,097	)		(2,056	)		(2,011	)
Amortization of tax regulatory assets		(2,492	)		(2,397	)		(2,362	)
Other, net		159			140			805
Total provision for (benefit from) income taxes	$	52,350		$	23,595		$	(9,844	)
ACCUMULATED DEFERRED INCOME TAXES
AS OF DECEMBER 31:
Property basis differences	$	216,933		$	193,409		$	177,262
Regulatory transition charge		101,190			151,129			196,812
Unamortized investment tax credits		(9,606	)		(10,472	)		(11,414	)
Deferred gain for asset sale to affiliated company		11,111			12,618			14,186
Other comprehensive income		14,084			8,121			(14,276	)
Above market leases		(120,078	)		(130,231	)		(140,399	)
Retirement benefits		41			(4,568	)		(9,768	)
Shopping credit incentive deferral		36,628			21,416			10,273
All Other		(28,353	)		(39,468	)		(64,397	)
Net deferred income tax liability	$	221,950		$	201,954		$	158,279

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

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

22

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.   ORGANIZATION AND BASIS OF PRESENTATION:

The consolidated financial statements include TE (Company) and its 90% owned subsidiary, TECC. TECC was formed in 1997 to make equity investments in a business trust in connection with financing related to the Bruce Mansfield Plant sale and leaseback transaction (see Note 5). CEI, an affiliate, has a 10% interest in TECC. 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 CEI, OE, 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 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 will continue 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 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	$	327		$	447
Customer shopping incentives		89			52
Liabilities to customers - income taxes		(10	)		(13	)
Loss on reacquired debt		3			3
Employee postretirement benefit costs		7			8
Asset removal costs and all other		(41	)		(38	)
Total	$	375		$	459

23

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 $89 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 2008.

Transition Cost Amortization-

The Company amortizes transition costs (see Regulatory Matters) using the effective interest method. Under the current Rate Stabilization Plan, total transition cost amortization is expected to approximate the following for 2005 through 2007:

	(In millions)
2005	$	139
2006		85
2007		95

Accounting for Generation Operations-

The application of SFAS 71 was discontinued in 2000 with respect to the Company's generation operations. The SEC's interpretive guidance and EITF 97-4 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 $53 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 $652 million 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 $2 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 $5 million (billed - $4 million and unbilled - $1 million) and $4 million (billed - $2 million and unbilled - $2 million) as of December 31, 2004 and 2003, respectively.

24

The Company and CEI sell substantially all of their retail customer receivables to CFC, a wholly owned subsidiary of CEI. 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.

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 ($1.6 million - the Company and $3.2 million - CEI) 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 3.8% in 2002.

Jointly - Owned Generating Stations-

The Company, together with CEI, 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 Plant in Service		Accumulated Provision for Depreciation		Construction Work in Progress		Ownership/ Leasehold Interest
Generating Units
	(In millions)
Bruce Mansfield Units 2 and 3	$	85	$	22	$	5		18.61	%
Beaver Valley Unit 2		15		1		10		19.91	%
Davis-Besse		305		66		31		48.62	%
Perry		357		74		5		19.91	%
Total	$	762	$	163	$	51

The Bruce Mansfield Plant and Beaver Valley Unit 2 are leased through sale and leaseback transactions (see Note 5) and the above-related amounts represent construction expenditures subsequent to the 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.

25

(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.

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 $505 million of goodwill. The impairment analysis includes a significant source of cash representing the Company's recovery of transition costs as described above 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 $8 million and unrealized gains on investments in securities available for sale of $28 million. As of December 31, 2003, accumulated other comprehensive income consisted of a minimum liability for unfunded retirement benefits of $9 million and unrealized gains on investments in securities available for sale of $21 million.

(G)   CUMULATIVE EFFECT OF ACCOUNTING CHANGE-

Results for 2003 include an after-tax credit to net income of $25.6 million recorded by the Company upon adoption of SFAS 143 in January 2003. The Company identified applicable legal obligations as defined under the new accounting standard for nuclear power plant decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $41.1 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $5.5 million. The asset retirement obligation liability at the date of adoption was $172 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 $179.6 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 $43.8 million increase to income, or $25.6 million net of income taxes.

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(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 the Company recognizing any tax losses or credits it contributed to the consolidated return.

(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, CEI, 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 CEI. The primary affiliated companies transactions are as follows:

	2004		2003		2002
	(In millions)
Operating Revenues:
PSA revenues from FES	$	204	$	103	$	128
Generating units rent from FES		15		15		14
Electric sales to CEI		101		109		104
Ground lease with ATSI		2		2		2
Operating Expenses:
Purchased power under PSA		311		298		319
Transmission expenses		--		19		23
FESC support services		36		35		26
Other Income:
Interest income from ATSI		3		3		3
Interest income from FES		10		10		10
Interest income from Shippingport (Note 6)		16		--		--

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 $55 million payable to affiliates for OPEB obligations.

The Company is selling 150 megawatts of its Beaver Valley Unit 2 leased capacity entitlement to CEI. Operating revenues for this transaction were $101 million, $109 million and $104 million in 2004, 2003 and 2002, respectively. This sale is expected to continue through the end of the lease period. (See Note 5.)

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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 $13 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 $8 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.

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.

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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	$	17		$	7		$	(36	)	$	(33	)
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	%

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

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	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	$	3		$	5		$	1		$	7		$	6		$	4

Weighted-Average Assumptions Used
to Determine Net Periodic Benefit Cost
for Years Ended December 31
	Pension Benefits									Other Benefits
	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	)

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 $3 million during 2004.

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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 $3 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 $11 million. As prescribed by SFAS 87, the company reduced its additional minimum liability by $1 million, recording an increase in an intangible asset of $1 million and crediting OCI by $2 million. The balance in AOCL of $8 million (net of $6 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 -

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 as of December 31:

	2004				2003
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Long-term debt	$	383	$	390	$	540	$	564

The fair value of long-term debt reflects 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:

	2004				2003
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Debt securities: (1)
-Government obligations	$	78	$	78	$	65	$	65
-Corporate debt securities		393		437		400		443
		471		515		465		508
Equity securities (1)		190		190		148		148
	$	661	$	705	$	613	$	656

⁽¹⁾ Includes nuclear decommissioning trust investments.

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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 securities. 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	$	106	$	5	$	1	$	110	$	91	$	5	$	--	$	96
Equity securities		143		47		2		188		114		40		9		145
	$	249	$	52	$	3	$	298	$	205	$	45	$	9	$	241

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	$	269	$	147	$	144
Gross realized gains		22		10		11
Gross realized losses		13		10		16
Interest and dividend income		9		7		6

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	$	40	$	1	$	1	$	--	$	41	$	1
Equity securities		29		1		5		1		34		2
	$	69	$	2	$	6	$	1	$	75	$	3

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. 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. Net unrealized gains and losses are recorded as regulatory liabilities or assets since the differences between investments held in trust and the decommissioning liabilities are recovered from or refunded to customers.

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.

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5.   LEASES:

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

The Company and CEI sold their ownership interests in Bruce Mansfield Units 1, 2 and 3 and the Company 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 CEI entered into operating leases for lease terms of approximately 30 years as co-lessees. During the terms of the leases, the Company and CEI 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 CEI have the right, at the end of the respective basic lease terms, to renew the leases. The Company and CEI 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 CEI, the Company is also obligated for CEI's lease payments. If CEI is unable to make its payments under the Bruce Mansfield Plant lease, the Company would be obligated to make such payments. No such payments have been made on behalf of CEI. (CEI's future minimum lease payments as of December 31, 2004 were approximately $0.2 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	$	46.2	$	49.4	$	52.6
Other		51.8		62.4		58.6
Capital leases
Interest element		--		--		--
Other		--		--		0.3
Total rentals	$	98.0	$	111.8	$	111.5

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

	Operating Leases
	Lease		Capital
	Payments		Trust		Net
	(In millions)
2005	$	104.8	$	25.3	$	79.5
2006		107.8		26.1		81.7
2007		99.2		22.6		76.6
2008		96.9		27.2		69.7
2009		98.1		23.3		74.8
Years thereafter		713.7		177.7		536.0
Total minimum lease payments	$	1,220.5	$	302.2	$	918.3

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 $111 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 $6 million per year). The total above-market lease obligation of $298 million associated with the Bruce Mansfield Plant is being amortized on a straight-line basis through the end of 2016 (approximately $19 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 $292 million, of which $25 million is payable within one year.

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The Company and CEI 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 ($145 million for the Company and $575 million for CEI) 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 ($337.1 million for the Company and $569.4 million for CEI) 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 obligations 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.

Shippingport was established to purchase all of the SLOBs issued in connection with the Company's and CEI's Bruce Mansfield Plant sale and leaseback transaction in 1987. The Company and CEI used debt and available funds to purchase the notes issued by Shippingport. Adoption of FIN 46R resulted in the consolidation of Shippingport by CEI as of December 31, 2003.

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 concluded that it was not the primary beneficiary of the owner trusts and it 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 applicable sale-leaseback agreements upon the occurrence of certain contingent events that the Company 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 agreements, the Company has net minimum discounted lease payments of $570 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 - $12 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 mid-2007 to as late as mid-2008;

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

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

On December 9, 2004, the PUCO rejected the auction price results from a required competitive bid process and issued an entry stating that the pricing under the approved revised Rate Stabilization Plan will take effect on January 1, 2006. The PUCO may 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 $0.1 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-

Preferred stock may be redeemed by the Company in whole, or in part, with 30-90 days’ notice.

The preferred dividend rates on the Company’s Series A and Series B shares fluctuate based on prevailing interest rates and market conditions. The dividend rates for both issues averaged 7% in 2004.

The Company has five million authorized and unissued shares of $25 par value preference stock.

(C)   LONG-TERM DEBT-

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. There also exist cross-default provisions among financing arrangements of FirstEnergy and the Company.

Sinking fund requirements for FMB and maturing long-term debt for the next five years are:

	(In millions)
2005	$	91
2006		--
2007		30
2008		--
2009		--

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. This amount of $91 million in 2005 represents 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 first mortgage bonds. Certain pollution control revenue bonds are entitled to the benefit of noncancelable municipal bond insurance policies of $149 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the policies, the Company is entitled to a credit against its obligation to repay those bonds. The Company pays annual premiums of 0.213% to 0.300% of the amounts of the policies to the insurers and is obligated to reimburse the insurers for any drawings thereunder.

The Company and CEI have unsecured LOCs of approximately $216 million in connection with the sale and leaseback of Beaver Valley Unit 2 that expire in April 2005. The Company and CEI are jointly and severally liable for the LOCs (see Note 5).

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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 and reclamation of a sludge disposal pond related to the Bruce Mansfield Plant. The ARO liability as of the date of adoption of SFAS 143 was $172 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. Accretion during 2004 was $12 million, bringing the ARO liability as of December 31, 2004 to $194 million. The ARO includes the Company's obligation for nuclear decommissioning of the Beaver Valley Unit 2, Davis-Besse, and Perry nuclear 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 $297.8 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 loss	$	(5	)
Increase (Decrease):
Elimination of decommissioning expense		29
Depreciation of asset retirement cost		(1	)
Accretion of ARO liability		(11	)
Non-regulated generation cost of removal component, net		1
Income tax effect		(7	)
Net earnings increase		11
Net income adjusted	$	6

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	$	182	$	172
Accretion		12		10
Ending balance as of December 31	$	194	$	182

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	$	161
Accretion		11
Ending balance as of December 31	$	172

11.   SHORT-TERM BORROWINGS:

Short-term borrowings outstanding as of December 31, 2004, consisted of $430 million from affiliates. The average interest rate on short-term borrowings outstanding as of December 31, 2004 and 2003, was 2.0% and 1.8% respectively.

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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 $89.0 million per incident but not more than $8.8 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 $332.1 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 $13.8 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.

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. NOx reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Company's facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states (including Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOx emissions are contributing significantly to ozone levels in the eastern United States. The Company believes its facilities are complying with the NOx 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.

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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" NOx 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. NOx 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 NOx 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 $0.2 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.

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.

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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 "recommendations to prevent or minimize the scope of future blackouts." 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.

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 which resulted in one case's dismissal being affirmed and the other 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.

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FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be instituted 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 19.91% 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

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to the Company's normal business operations 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.

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.

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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 TE 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.

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.

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14.   SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):

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

	March 31, 2004		June 30, 2004		September 30, 2004		December 31, 2004
Three Months Ended
	(In millions)
Operating Revenues	$	235.4	$	243.4	$	276.3	$	253.0
Operating Expenses and Taxes		224.9		216.7		251.4		221.9
Operating Income		10.5		26.7		24.9		31.1
Other Income		5.8		4.7		4.2		8.3
Net Interest Charges		8.8		9.8		4.6		6.6
Net Income	$	7.5	$	21.6	$	24.5	$	32.8
Earnings on Common Stock	$	5.3	$	19.4	$	22.2	$	30.5

	March 31,			June 30,			September 30,		December 31,
Three Months Ended	2003			2003			2003		2003
	(In millions)
Operating Revenues	$	231.8		$	216.0		$	260.2	$	224.3
Operating Expenses and Taxes		226.5			217.9			241.4		210.9
Operating Income (Loss)		5.3			(1.9	)		18.8		13.4
Other Income		3.1			3.8			5.7		8.0
Net Interest Charges		9.1			11.1			7.9		8.3
Income (Loss) Before Cumulative Effect of Accounting Change		(0.7	)		(9.2	)		16.6		13.1
Cumulative Effect of Accounting Change (Net of Income Taxes)		25.6			--			--		--
Net Income (Loss)	$	24.9		$	(9.2	)	$	16.6	$	13.1
Earnings on Common Stock	$	22.7		$	(11.4	)	$	14.4	$	10.9

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