OHIO EDISON COMPANY

2004 ANNUAL REPORT TO STOCKHOLDERS

Ohio Edison Company is a wholly owned electric utility operating subsidiary of FirstEnergy Corp. Ohio Edison engages in the generation, distribution and sale of electric energy to communities in an area of 7,500 square miles in central and northeastern Ohio and, through its wholly owned Pennsylvania Power Company subsidiary, 1,500 square miles in western Pennsylvania. It also engages in the sale, purchase and interchange of electric energy with other electric companies.

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		19-20
Consolidated Statements of Common Stockholder's Equity		21
Consolidated Statements of Preferred Stock		21
Consolidated Statements of Cash Flows		22
Consolidated Statements of Taxes		23
Notes to Consolidated Financial Statements		24-44

GLOSSARY OF TERMS

The following abbreviations and acronyms are used in this report to identify Ohio 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
Companies	OE and Penn
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
Ohio Companies	CEI, OE and TE
Penelec	Pennsylvania Electric Company, an affiliated Pennsylvania electric utility
Penn	Pennsylvania Power Company, OE's wholly owned Pennsylvania electric utility subsidiary
PNBV	PNBV Capital Trust, a special purpose entity created by OE in 1996
TE	The Toledo Edison Company, an affiliated Ohio electric utility
The following abbreviations and acronyms are used to identify frequently used terms in this report:
ALJ	Administrative Law Judge
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 Coordination Agreement
EITF	Emerging Issues Task Force
EITF 03-1	EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its Application to Certain Investments”
EITF 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 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
LOC	Letter of Credit
MACT	Maximum Achievable Control Technologies
Medicare Act	Medicare Prescription Drug, Improvement and Modernization Act of 2003
MISO	Midwest Independent Transmission System Operator, Inc.

i

GLOSSARY OF TERMS, Cont.

Moody’s	Moody’s Investors Service
MW	Megawatts
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Council
NOAC	Northwest Ohio Aggregation Coalition
NOV	Notices of Violation
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.
PLR	Provider of Last Resort
PPUC	Pennsylvania Public Utility Commission
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 143	SFAS No. 143, "Accounting for Asset Retirement Obligations"
SFAS 144	SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"
SFAS 150	SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity"
SO2	Sulfur Dioxide
SPE	Special Purpose Entity
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 auditors’ 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 Ohio Edison Company:

We have completed an integrated audit of Ohio 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 Ohio Edison Company and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2(G) to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations as of January 1, 2003. As discussed in Note 7 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 ofinternal 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 ofthe 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

OHIO EDISON COMPANY

SELECTED FINANCIAL DATA

	2004			2003			2002			2001			2000
	(Dollars in thousands)
Operating Revenues	$	2,945,583		$	2,925,310		$	2,948,675		$	3,056,464		$	2,726,708
Operating Income	$	335,529		$	336,936		$	453,831		$	466,819		$	482,321
Income Before Cumulative Effect of Accounting Change	$	342,766		$	292,925		$	356,159		$	350,212		$	336,456
Net Income	$	342,766		$	324,645		$	356,159		$	350,212		$	336,456
Earnings on Common Stock	$	340,264		$	321,913		$	349,649		$	339,510		$	325,332
Total Assets	$	6,482,651		$	7,316,930		$	7,790,041		$	7,915,953		$	8,154,151
Capitalization as of December 31:
Common Stockholder's Equity	$	2,493,809		$	2,582,970		$	2,839,255		$	2,671,001		$	2,556,992
Preferred Stock:
Not Subject to Mandatory Redemption		100,070			100,070			100,070			200,070			200,070
Subject to Mandatory Redemption		--			--			13,500			134,250			135,000
Long-Term Debt and Other Long-Term Obligations		1,114,914			1,179,789			1,219,347			1,614,996			2,000,622
Total Capitalization	$	3,708,793		$	3,862,829		$	4,172,172		$	4,620,317		$	4,892,684
Capitalization Ratios:
Common Stockholder's Equity		67.2	%		66.9	%		68.1	%		57.8	%		52.3	%
Preferred Stock:
Not Subject to Mandatory Redemption		2.7			2.6			2.4			4.3			4.1
Subject to Mandatory Redemption		--			--			0.3			2.9			2.7
Long-Term Debt and Other Long-Term Obligations		30.1			30.5			29.2			35.0			40.9
Total Capitalization		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%
Distribution KWH Deliveries (Millions):
Residential		10,180			10,009			10,233			9,646			9,432
Commercial		8,276			8,105			7,994			7,967			8,221
Industrial		10,700			10,658			10,672			10,995			11,631
Other		144			160			154			152			151
Total		29,300			28,932			29,053			28,760			29,435
Customers Served:
Residential		1,056,560			1,044,419			1,041,825			1,033,414			1,014,379
Commercial		129,017			127,856			119,771			118,469			116,931
Industrial		1,149			1,182			4,500			4,573			4,569
Other		1,751			1,752			1,756			1,664			1,606
Total		1,188,477			1,175,209			1,167,852			1,158,120			1,137,485
Number of Employees		1,370			1,521			1,569			1,618			1,647

3

OHIO 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 as disclosed in our Securities and Exchange Commission filings, generally, the availability and cost of capital, the continuing availability and operation of generating units, our ability to experience growth in the distribution business, our ability to access the public securities and other capital markets, further investigation into the causes of the August 14, 2003, regional power outage and the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the outage, the final outcome in the proceeding related to our Application for a Rate Stabilization Plan in Ohio, the risks and other factors discussed from time to time in our Securities and Exchange Commission filings, and other similar factors. We expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events, or otherwise.

Results of Operations

Earnings on common stock in 2004 increased to $340 million from $322 million in 2003. Earnings on common stock in 2003 included an after-tax gain of $32 million from the cumulative effect of an accounting change due to the adoption of SFAS 143 (see Note 2(G)). Income before the cumulative effect of an accounting change was $293 million in 2003. The earnings increase in 2004 primarily resulted from lower nuclear operating costs and reduced financing costs, partially offset by higher purchased power costs compared to 2003. Earnings in 2003 decreased to $322 million from $350 million in 2002. The decrease primarily resulted from increased nuclear outage related costs, increased amortization of the Ohio transition regulatory assets and reduced operating revenues. These items were partially offset by reduced nuclear fuel expenses as a result of the additional nuclear outages, reduced financing costs and the after-tax credit from the 2003 cumulative effect of an accounting change.

Operating revenues increased by $20 million (0.7%) in 2004 compared with 2003 primarily due to increases of $22 million in wholesale sales and $12 million in retail generation revenues partially offset by $16 million shopping incentive credits discussed below. Revenues from wholesale sales to FES (resulting from increased nuclear generation available for sale) increased by $29 million, and was partially offset by $10 million of lower revenues due to the expiration of a contract in July 2003. The higher retail generation revenues primarily resulted from a $9 million increase in sales to industrial customers, reflecting a 1.1 percentage point decrease in electric generation services provided by alternative suppliers as a percent of total sales delivered in our service areas. Revenues from sales to residential customers decreased by $2 million as the corresponding percentage for shopping increased by 2.5 percentage points. Commercial sector revenues increased by $5 million due to higher KWH sales and unit prices -- the percentage of customers shopping remained relatively unchanged.

Operating revenues decreased by $23 million (0.8%) in 2003 compared with 2002 due to cooler-than-normal temperatures in the second and third quarters of 2003 and increased sales by alternative suppliers. The lower revenues primarily resulted from reduced generation sales revenues, which included all retail customer categories - residential, commercial and industrial. KWH sales to retail customers declined by 8.1% in 2003 from the prior year, reducing generation sales revenue by $98 million. Electric generation services provided to retail customers by alternative suppliers as a percent of total KWH delivered in the franchise area increased 6.1 percentage points in 2003 from 2002. Sales revenues from wholesale customers increased by $47 million in 2003 compared with 2002. This increase resulted from higher unit prices, partially offset by lower KWH sales to FES due to reduced nuclear generation available for sale.

4

Revenues from distribution throughput increased $3 million in 2004 compared with 2003. Distribution deliveries to commercial customers increased by $11 million in 2004 compared to 2003, reflecting increased KWH deliveries (2.1%) and higher unit prices. Lower unit prices offset the effect of higher throughput resulting in a decrease of $9 million in revenues from industrial customers. The increased sales to the commercial and industrial sectors resulted from the improving economy in our service areas. Revenues from distribution throughput increased by $35 million in 2003 for all retail customer - classes compared with 2002, primarily due to higher unit prices partially offset by the effects of slightly lower KWH deliveries in 2003.

Under the Ohio transition plan, we provide incentives to customers to encourage switching to alternative energy providers - $16 million of additional credits in 2004 compared to $8 million of additional credits in 2003 from 2002. These revenue reductions are deferred for future recovery under OE’s transition plan and do not affect current period earnings.

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

Changes in KWH Sales
Increase (Decrease)	2004			2003
Electric Generation:
Retail		0.5	%		(8.1	)%
Wholesale		7.3	%		(10.5	)%
Total Electric Generation Sales		3.7	%		(9.2	)%
Distribution Deliveries:
Residential		1.7	%		(2.2	)%
Commercial		2.1	%		1.4	%
Industrial		0.4	%		(0.1	)%
Total Distribution Deliveries		1.3	%		(0.4	)%

Operating Expenses and Taxes

Total operating expenses and taxes increased by $22 million in 2004 and by $94 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	$	4		$	(3	)
Purchased power costs		56			(17	)
Nuclear operating costs		(57	)		80
Other operating costs		(27	)		--
Provision for depreciation		5			(24	)
Amortization of regulatory assets		18			58
Deferral of new regulatory assets		(27	)		19
General taxes		10			(7	)
Income taxes		40			(12	)
Total operating expenses and taxes	$	22		$	94

Higher fuel costs in 2004 compared to 2003, resulted from increased nuclear generation - up 13.1%. Purchased power costs were higher in 2004 due to higher unit costs. Lower nuclear operating costs in 2004 were primarily the result of one scheduled refueling outage in 2004 compared to three scheduled refueling outages in 2003. The decrease in other operating costs in 2004 compared to 2003 was due to reduced labor costs and lower employee benefits expenses.

Lower fuel costs in 2003 compared to 2002 resulted from reduced nuclear generation - down 10.5%. In 2003, the KWH purchase requirements were lower than in 2002 because of reduced electric generation sales - those cost reductions were partially offset by the effect of higher unit costs. Higher nuclear operating costs in 2003 were driven by three nuclear refueling outages compared with one refueling outage in 2002. The Beaver Valley Unit 1 and Perry refueling outages in 2003 included additional unplanned work, which extended the length of the outages and increased their cost.

5

Provision for depreciation increased in 2004 compared to 2003 primarily due to a slight change in the composite depreciation rate and a higher depreciable asset base. Decreased depreciation charges in 2003 compared to 2002 were primarily due to lower charges resulting from the implementation of SFAS 143 ($19 million). Increases in amortization of regulatory assets in 2004 and 2003 compared to the prior year relates to higher amortization of Ohio transition regulatory assets. The higher deferrals of new regulatory assets in 2004 compared to 2003 primarily relates to higher shopping incentive deferrals ($16 million) and deferred interest on shopping incentives ($10 million). The decrease in deferrals in 2003 from 2002 was due to reduced tax-related deferrals ($27 million) partially offset by higher shopping incentive deferrals ($8 million).

General taxes increased by $10 million in 2004 and decreased by $7 million in 2003, primarily due to a property tax settlement in 2003. In 2003, the tax settlement was partially offset by higher KWH excise taxes.

Other Income

Other income increased $7 million in 2004 compared to 2003, primarily due to gains on disposition of property. In 2003, other income increased by $24 million from the prior year, primarily due to the absence in 2003 of charges in 2002 related to low-income housing investments.

Net Interest Charges

Net interest charges continued to trend lower, decreasing by $44 million in 2004 and $30 million in 2003. We continued to redeem and refinance outstanding debt during 2004 - net redemptions and refinancing activities totaled $121 million and $245 million, respectively.

Cumulative Effect of Accounting Change

Upon adoption of SFAS 143 in the first quarter of 2003, we recorded an after-tax credit to net income of $32 million. The cumulative adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $54 million increase to income, or $32 million net of income taxes.

Capital Resources and Liquidity

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

Changes in Cash Position

As of December 31, 2004, we had $1 million 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.

Cash Flows From Operating Activities

Cash provided from operating activities during 2004, 2003 and 2002 are as follows:

Operating Cash Flows	2004			2003		2002
	(In millions)
Cash earnings (1)	$	776		$	689	$	743
Pension trust contribution (2)		(44	)		--		--
Working capital and other		(312	)		371		330
Total	$	420		$	1,060	$	1,073

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

⁽²⁾ Pension trust contribution net of $29 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.

6

Reconciliation of Cash Earnings	2004			2003			2002
	(In millions)
Net Income (GAAP)	$	343		$	325		$	356
Non-Cash Charges (Credits):
Provision for depreciation		122			118			142
Amortization of regulatory assets		411			393			336
Nuclear fuel and capital lease amortization		43			39			48
Deferral of new regulatory assets		(101	)		(73	)		(92	)
Deferred income taxes and investment tax credits, net		(73	)		(88	)		(76	)
Cumulative effect of accounting change		--			(54	)		--
Other non-cash charges		31			29			29
Cash earnings (Non-GAAP)	$	776		$	689		$	743

Net cash from operating activities decreased $640 million in 2004 compared to 2003 due to a $683 million decrease from changes in working capital and a $44 million after-tax voluntary pension trust contribution. These decreases were partially offset by a $87 million increase in cash earnings as described above under “Results from Operations”. The change in working capital primarily reflects decreases in accounts payable and accrued tax balances. In 2004 tax liabilities among affiliated companies were settled in accordance with the tax sharing agreement, reducing our accrued taxes by $249 million. Accrued taxes were also reduced by a $169 million federal income tax payment in 2004.

Net cash provided from operating activities decreased $13 million in 2003 compared to 2002 due to a $54 million decrease from cash earnings as described under "Results of Operations" partially offset by a $41 million increase in working capital requirements. The increase in working capital requirements primarily represents changes in receivables partially offset by decreased accounts payable and accrued tax balances.

Cash Flows From Financing Activities

In 2004, 2003 and 2002, net cash used for financing activities of $569 million, $982 million and $599 million, respectively, primarily reflect debt redemptions and common stock dividend payments to FirstEnergy. The following table provides details regarding new issues and redemptions during each year:

Securities Issued or Redeemed	2004			2003			2002
	(In millions)
New Issues
Pollution Control Notes	$	30		$	--		$	15
Unsecured Notes		--			325			--
Long-Term Revolving Credit		--			40			--
	$	30		$	365		$	15
Redemptions
First Mortgage Bonds	$	63		$	410		$	280
Pollution Control Notes		--			30			15
Secured Notes		62			62			127
Preferred Stock		1			1			221
Long-Term Revolving Credit		40			--			--
Other, principally redemption premiums		6			17			4
	$	172		$	520		$	647
Short-term Borrowings, Net (use)/source of cash	$	(4	)	$	(225	)	$	162

Net cash used for financing activities increased to $569 million in 2004 from $982 million in 2003. The decrease resulted from a net reduction of $234 million of debt refinancings and a $178 million reduction of common stock dividends to FirstEnergy. The $383 million increase in net cash used for financing activities in 2003 from 2002 was principally due to a $477 million increase in dividends to FirstEnergy partially offset by a $90 million decrease in net debt redemptions.

On June 7, 2004, we replaced certain collateralized LOCs that were issued in 1994 in support of our obligations to lessors under the Beaver Valley Unit 2 sale and leaseback arrangements. Approximately $289 million in cash collateral and accrued interest previously held by OES Finance Incorporated, our wholly owned subsidiary, was released on July 15, 2004 upon cancellation of the existing LOCs and was used primarily to repay short-term debt. Simultaneously with the issuance of the replacement LOCs, OE entered into a Credit Agreement pursuant to which a standby LOC was issued in support of the replacement LOCs, and the issuer of the LOCs obtained the right to pledge or assign participations in our reimbursement obligations to a trust. The trust then issued and sold trust certificates to institutional investors that were designed to be the credit equivalent of an investment directly in OE.

7

We had approximately $540 million of cash and temporary investments (which include short-term notes receivable from associated companies) and approximately $179 million of short-term indebtedness as of December 31, 2004. Available borrowing capability under bilateral bank facilities totaled $13 million as of December 31, 2004. We have obtained authorization from the PUCO to incur short-term debt of up to $500 million (including bank facilities and the utility money pool described below). Penn has obtained authorization from the SEC to incur short-term debt up to its charter limit of $51 million (including the utility money pool). At the end of 2004, we had the aggregate capability to issue approximately $2.0 billion of additional FMB on the basis of property additions and retired bonds under the terms of our mortgage indentures. The issuance of FMB by us is also subject to provisions of our senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit us to incur additional secured debt not otherwise permitted by a specified exception of up to $641 million, as of December 31, 2004. The OE Companies could issue a total of $3.2 billion of preferred stock (assuming no additional debt was issued) as of the end of 2004.

Our $125 million 364-day revolving credit facility was restructured through a new syndicated FirstEnergy facility that was completed on June 22, 2004. Combined with our existing syndicated $125 million three-year facility maturing in October 2006, our existing syndicated $250 million two-year facility maturing in May 2005 and bank facilities of $34 million, our credit facilities total $409 million, of which $388 million was unused as of December 31, 2004. These facilities are intended to provide liquidity to meet our short-term working capital requirements and would be available for investment in the money pool with our regulated affiliates.

Borrowings under these facilities are conditioned on maintaining compliance with certain financial covenants in the agreement. Under our $125 million 364-day and $250 million two-year facilities, we are required to maintain a debt to total capitalization ratio of no more than 0.65 to 1 and a contractually-defined fixed charge coverage ratio of no less than 2 to 1. We are in compliance with these financial covenants. As of December 31, 2004, our fixed charge coverage ratio, as defined under the credit agreements, was 7.15 to 1. Our debt to total capitalization ratio, as defined under the credit agreements, was 0.39 to 1. The ability to draw on these facilities is also conditioned upon our making certain representations and warranties to the lending banks prior to drawing on its facilities, including a representation that there has been no material adverse change in our business, condition (financial or otherwise), results of operations, or prospects.

Our primary credit facilities contain no provisions restricting our ability to borrow, or accelerating repayment of outstanding loans, as a result of any change in our S&P or Moody's credit ratings. The primary facilities do contain “pricing grids”, whereby the cost of funds borrowed under the facilities is related to our credit ratings.

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 the respective regulated subsidiaries, as well as proceeds available from bank borrowings. For the regulated companies, available bank borrowings include $1.75 billion from FirstEnergy’s and our revolving credit facilities. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings under these arrangements in 2004 was 1.43%.

In March 2004, Penn completed receivables financing arrangement that provides borrowing capability of up to $25 million. The borrowing rate is based on bank commercial paper rates. Penn is required to pay an annual facility fee of 0.40% on the entire finance limit. The facility was undrawn as of December 31, 2004 and matures on March 29, 2005. Penn plans to renew the agreement. On December 1, 2004, Ohio Air Quality Development Authority Series 1999-C pollution control notes aggregating $47,725,000 were remarketed in a Dutch Auction interest mode, insured with municipal bond insurance and secured with first mortgage bonds.

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.

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Ratings of Securities
	Securities		S&P		Moody’s		Fitch
FirstEnergy		Senior unsecured		BB+		Baa3		BBB-
Ohio Edison		Senior secured		BBB		Baa1		BBB+
		Senior unsecured		BB+		Baa2		BBB
		Preferred stock		BB		Ba1		BBB-
Penn		Senior secured		BBB		Baa1		BBB+
		Senior unsecured(1)		BB+		Baa2		BBB
		Preferred stock		BB		Ba1		BBB-

⁽¹⁾   Penn's only senior unsecured debt obligations are notes underlying pollution control revenue refunding bonds issued by the Ohio Air Quality Development Authority to which bonds this rating applies

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 provided from investing activities totaled $149 million in 2004 compared to $97 million used for investing activities in 2003. The $246 million change resulted primarily from $278 million of cash proceeds from certificates of deposit in the third quarter of 2004 and a $62 million increase in loan repayments from associated companies. These increases were offset by a $46 million increase in property additions. Net cash used for investing activities in 2003 decreased by $362 million from 2002. The decrease was primarily due to a $394 million increase in cash payments received on long-term notes receivable offset by a $40 million increase in property additions.

Our capital spending for the period 2005-2007 is expected to be about $667 million (excluding nuclear fuel), of which approximately $215 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to be approximately $138 million, of which about $34 million applies to 2005. During the same period, our nuclear fuel investments are expected to be reduced by approximately $125 million and $41 million, respectively, as the nuclear fuel is consumed.

Contractual Obligations

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

					2006-		2008-
Contractual Obligations	Total		2005		2007		2009		Thereafter
	(In millions)
Long-term debt (4)	$	1,504	$	134	$	12	$	181	$	1,177
Short-term borrowings		179		179		--		--		--
Preferred stock (1)		13		1		12		--		--
Capital leases		11		4		5		1		1
Operating leases (2)		1,158		82		160		203		713
Purchases (3)		194		34		101		59		--
Total	$	3,059	$	434	$	290	$	444	$	1,891

⁽¹⁾   Subject to mandatory redemption.

⁽²⁾   Operating lease payments are net of capital trust receipts of $532.4 million (see Note 6).

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

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

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Off-Balance Sheet Arrangements

We have obligations that are not included on our Consolidated Balance Sheets related to the sale and leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2, which are reflected as part of the operating lease payments disclosed above (see Note 6 - Leases). The present value of these operating lease commitments, net of trust investments, was $673 million 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, as noted in the following table which presents principal amounts and related weighted average interest rates by year of maturity for our investment portfolio, debt obligations and preferred stock with mandatory redemption provisions.

Comparison of Carrying Value to Fair Value
																There-						Fair
Year of Maturity	2005			2006			2007			2008			2009			after			Total			Value
	(Dollars in millions)
Assets
Investments Other Than Cash
and Cash Equivalents-
Fixed Income	$	31		$	36		$	39		$	17		$	26		$	639		$	788		$	887
Average interest rate		8.0	%		8.1	%		8.2	%		8.2	%		8.5	%		7.2	%		7.4	%
Liabilities Long-term Debt and Other
Long-Term Obligations:
Fixed rate	$	134		$	6		$	6		$	179		$	2		$	466		$	793		$	816
Average interest rate		7.2	%		7.9	%		7.9	%		4.1	%		8.0	%		6.0	%		5.8	%
Variable rate																$	711		$	711		$	712
Average interest rate																	2.1	%		2.1	%
Preferred Stock Subject to Mandatory Redemption	$	1		$	1		$	11											$	13		$	12
Average dividend rate		7.6	%		7.6	%		7.6	%											7.6	%
Short-term Borrowings		179																	$	179		$	179
Average interest rate		2.3	%																	2.3	%

Equity Price Risk

Included in our nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $248 million and $208 million as of December 31, 2004 and 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $25 million reduction in fair value as of December 31, 2004 (see Note 5 - 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. In Ohio and Pennsylvania, 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 Ohio 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 for OE customers), and the customer receives a generation charge from the alternative supplier. OE has continuing PLR responsibility to its franchise customers through December 31, 2005.

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Regulatory assets are costs which have been authorized by the PUCO, the PPUC 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. All regulatory assets are expected to be recovered under the provisions of our transition plan and rate restructuring plan. Our regulatory assets were as follows:

Regulatory Assets as of December 31,
Company	2004*		2003
	(In millions)
Ohio Edison	$	1,116	$	1,450
Penn		--		28
Consolidated Total	$	1,116	$	1,478

   *  Changes in Penn's net regulatory asset components in 2004 resulted in net regulatory liabilities of approximately $18 million 

      included in Other Noncurrent Liabilities on the Consolidated Balance Sheet as of December 31, 2004.

As part of our Ohio transition plan, we are obligated to supply electricity to customers who do not choose an alternative supplier. The Company is also required to provide 560 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 our amortization period for transition costs being recovered through the RTC from 2006 to as late as 2007;

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

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

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

On December 30, 2004, we filed an application with the PUCO seeking tariff adjustments to recover increases of approximately $14 million in transmission and ancillary service costs beginning January 1, 2006. 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 and Pennsylvania.

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 NOx reduction requirements. We continue to evaluate our compliance plans and other compliance options.

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Clean Air Act Compliance-

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

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

National Ambient Air Quality Standards-

   In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On December 17, 2003, the EPA proposed the "Interstate Air Quality Rule" covering a total of 29 states (including Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air pollution emissions from 29 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. The EPA has proposed the Interstate Air Quality Rule to "cap-and-trade" 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 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 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.

    W. H. Sammis Plant-

In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities covering 44 power plants, including the W. H. Sammis Plant, which is owned by OE and Penn. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase of the trial to address any civil penalties and what, if any, actions should be taken to further reduce emissions at the plant has been delayed without rescheduling by the Court because the parties are engaged in meaningful settlement negotiations. The Court indicated, in its August 2003 ruling, that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact on our financial condition and results of operations. While the parties are engaged in meaningful settlement discussions, management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of December 31, 2004.

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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.

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

   Clean Water Act-

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

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

Other Legal Proceedings

Power Outages and Related Litigation-

Three substantially similar actions were filed in various Ohio state courts by plaintiffs seeking to represent customers who allegedly suffered damages as a result of the August 14, 2003 power outages. All three cases were dismissed for lack of jurisdiction. One case was refiled at the PUCO. The other two cases were appealed. One case was dismissed and no further appeal was sought. The remaining case is pending. In addition to the one case that was refiled at the PUCO, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages.

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

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against us. 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.

13

Other Legal Matters-

Various lawsuits, claims (including claims for asbestos exposure) and proceedings related to our normal business operations are pending against us, the most significant of which are described herein.

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 35.24% 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.

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

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

Critical Accounting Policies

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

Regulatory Accounting

We are subject to regulation that sets the prices (rates) we are permitted to charge our customers based on 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 ratemaking process results in the recording of regulatory assets based on anticipated future cash inflows. We regularly review these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future.

Revenue Recognition

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

Pension and Other Postretirement Benefits Accounting

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

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

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

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

Our assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by 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 $73 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 $48 million. As prescribed by SFAS 87, we increased our additional minimum liability by $18 million, recording an increase in an intangible asset of $5 million and charging $13 million to OCI. The balance in AOCL of $69 million (net of $49 million in deferred taxes) will reverse in future periods to the extent the fair value of trust assets exceeds the accumulated benefit obligation.

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

Ohio Transition Cost Amortization

In connection with our initial Ohio 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 had not yet been incurred. 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 Stablization 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 judgment 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.

15

Nuclear Decommissioning

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

New Accounting Standards and Interpretations

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

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

16

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31,	2004			2003			2002
	(In thousands)
OPERATING REVENUES (Note 2(I))	$	2,945,583		$	2,925,310		$	2,948,675
OPERATING EXPENSES AND TAXES:
Fuel		56,560			52,169			55,337
Purchased power (Note 2(I))		970,670			914,723			931,400
Nuclear operating costs		375,309			432,315			352,129
Other operating costs (Note 2(I))		336,772			363,989			364,436
Provision for depreciation		122,413			117,895			142,083
Amortization of regulatory assets		411,326			393,409			335,523
Deferral of new regulatory assets		(100,633	)		(73,183	)		(92,086	)
General taxes		180,523			170,078			177,021
Income taxes		257,114			216,979			229,001
Total operating expenses and taxes		2,610,054			2,588,374			2,494,844
OPERATING INCOME		335,529			336,936			453,831
OTHER INCOME (Note 2(I))		74,077			66,782			42,859
NET INTEREST CHARGES:
Interest on long-term debt		59,465			91,068			119,123
Allowance for borrowed funds used during construction and capitalized interest		(7,211	)		(6,075	)		(3,639	)
Other interest expense		12,026			22,340			14,598
Subsidiary's preferred stock dividend requirements		2,560			3,460			10,449
Net interest charges		66,840			110,793			140,531
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		342,766			292,925			356,159
Cumulative effect of accounting change (net of income taxes of $22,389,000) (Note 2(G))		--			31,720			--
NET INCOME		342,766			324,645			356,159
PREFERRED STOCK DIVIDEND REQUIREMENTS		2,502			2,732			6,510
EARNINGS ON COMMON STOCK	$	340,264		$	321,913		$	349,649

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

17

OHIO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS

As of December 31,	2004		2003
	(In thousands)
ASSETS
UTILITY PLANT:
In service	$	5,440,374	$	5,269,042
Less-Accumulated provision for depreciation		2,716,851		2,578,899
		2,723,523		2,690,143
Construction work in progress-
Electric plant		203,167		145,380
Nuclear fuel		21,694		554
		224,861		145,934
		2,948,384		2,836,077
OTHER PROPERTY AND INVESTMENTS:
Investment in lease obligation bonds (Note 6)		354,707		383,510
Certificates of deposit (Note 9(C))		--		277,763
Nuclear plant decommissioning trusts		436,134		376,367
Long-term notes receivable from associated companies		208,170		508,594
Other		48,579		59,102
		1,047,590		1,605,336
CURRENT ASSETS:
Cash and cash equivalents		1,230		1,883
Receivables-
Customers (less accumulated provisions of $6,302,000 and $8,747,000,
respectively, for uncollectible accounts)		274,304		280,538
Associated companies		245,148		436,991
Other (less accumulated provision of $64,000 and $2,282,000, respectively, for uncollectible accounts)		18,385		28,308
Notes receivable from associated companies		538,871		366,501
Materials and supplies, at average cost		90,072		79,813
Prepayments and other		13,104		14,390
		1,181,114		1,208,424
DEFERRED CHARGES:
Regulatory assets		1,115,627		1,477,969
Property taxes		61,419		59,279
Unamortized sale and leaseback costs		60,242		65,631
Other		68,275		64,214
		1,305,563		1,667,093
	$	6,482,651	$	7,316,930
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity	$	2,493,809	$	2,582,970
Preferred stock not subject to mandatory redemption		60,965		60,965
Preferred stock of consolidated subsidiary not subject to mandatory redemption		39,105		39,105
Long-term debt and other long-term obligations		1,114,914		1,179,789
		3,708,793		3,862,829
CURRENT LIABILITIES:
Currently payable long-term debt		398,263		466,589
Short-term borrowings-
Associated companies		11,852		11,334
Other		167,007		171,540
Accounts payable-
Associated companies		187,921		271,262
Other		10,582		7,979
Accrued taxes		153,400		560,345
Accrued interest		11,992		18,714
Other		62,671		58,680
		1,003,688		1,566,443
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		766,276		867,691
Accumulated deferred investment tax credits		62,471		75,820
Asset retirement obligation		339,134		317,702
Retirement benefits		307,880		331,829
Other		294,409		294,616
		1,770,170		1,887,658
COMMITMENTS AND CONTINGENCIES (Notes 6 and 12)
	$	6,482,651	$	7,316,930

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

18

OHIO 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, without par value, authorized 175,000,000 shares-100 shares outstanding	$	2,098,729		$	2,098,729
Accumulated other comprehensive loss (Note 2(F))		(47,118	)		(38,693	)
Retained earnings (Note 9(A))		442,198			522,934
Total common stockholder's equity		2,493,809			2,582,970

	Number of Shares				Optional
	Outstanding				Redemption Price
	2004		2003		Per Share		Aggregate
PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION (Note 9(B)):
Cumulative, $100 par value-
Authorized 6,000,000 shares
3.90%		152,510		152,510	$	103.63	$	15,804	15,251	15,251
4.40%		176,280		176,280		108.00		19,038	17,628	17,628
4.44%		136,560		136,560		103.50		14,134	13,656	13,656
4.56%		144,300		144,300		103.38		14,917	14,430	14,430
Total		609,650		609,650			$	63,893	60,965	60,965
PREFERRED STOCK OF CONSOLIDATED SUBSIDIARY NOT SUBJECT TO MANDATORY REDEMPTION (Note 9(B)):
Pennsylvania Power Company-
Cumulative, $100 par value-
Authorized 1,200,000 shares
4.24%		40,000		40,000	$	103.13	$	4,125	4,000	4,000
4.25%		41,049		41,049		105.00		4,310	4,105	4,105
4.64%		60,000		60,000		102.98		6,179	6,000	6,000
7.75%		250,000		250,000		100.00		25,000	25,000	25,000
Total		391,049		391,049			$	39,614	39,105	39,105

19

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)

As of December 31,	2004		2003				2004		2003		2004			2003
	(In thousands)
LONG-TERM DEBT AND OTHER
LONG-TERM OBLIGATIONS (Note 9(C)):
First mortgage bonds:
Ohio Edison Company-					Pennsylvania Power Company-
6.875% due 2005		80,000		80,000		9.740% due 2005-2019		14,643		15,617
						6.375% due 2004		--		20,500
						6.625% due 2004		--		14,000
						8,500% due 2022		--		27,250
						7.625% due 2023		6,500		6,500
Total first mortgage bonds		80,000		80,000				21,143		83,867		101,143			163,867
Secured notes:
Ohio Edison Company-					Pennsylvania Power Company-
7.680% due 2005		51,461		109,081		5.400% due 2013		1,000		1,000
*  1.700% due 2015		19,000		19,000		5.400% due 2017		10,600		10,600
6.750% due 2015		40,000		40,000		*  1.700% due 2017		17,925		17,925
*   3.250% due 2015		50,000		50,000		5.900% due 2018		16,800		16,800
*   1.800% due 2016		47,725		--		*  1.700% due 2021		14,482		14,482
7.050% due 2020		60,000		60,000		6.150% due 2023		12,700		12,700
*   1.700% due 2021		443		443		*  2.000% due 2027		10,300		10,300
5.375% due 2028		13,522		13,522		5.375% due 2028		1,734		1,734
5.625% due 2029		50,000		50,000		5.450% due 2028		6,950		6,950
5.950% due 2029		56,212		56,212		6.000% due 2028		14,250		14,250
*   1.710% due 2030		60,400		60,400		5.950% due 2029		238		238
*   1.700% due 2031		69,500		69,500		1.800% due 2033		5,200		--
*   1.800% due 2033		44,800		44,800
1.750% due 2033		12,300		12,300
5.450% due 2033		14,800		14,800
*   2.250% due 2033		50,000		50,000
1.800% due 2033		108,000		--
Limited Partnerships-
7.35% weighted average  interest rate due 2005-2010
		17,272		21,432
Total secured notes		765,435		671,490				112,179		106,979		877,614			778,469
Unsecured notes:
Ohio Edison Company-					Pennsylvania Power Company-
*    2.238% due 2005		--		40,000		*  3.375% due 2029		14,500		14,500
4.000% due 2008		175,000		175,000		*  5.900% due 2033		--		5,200
*    1.980% due 2014		50,000		50,000
5.450% due 2015		150,000		150,000
*    5.800% due 2016		--		47,725
*    2.230% due 2018		33,000		33,000
*    2.150% due 2018		23,000		23,000
*    2.150% due 2023		50,000		50,000
*    4.650% due 2033		--		108,000
*    3.350% due 2033		30,000		--
Total unsecured notes		511,000		676,725				14,500		19,700		525,500			696,425
Preferred stock subject to mandatory redemption												12,750			13,500
Capital lease obligations (Note 6)												5,223			6,829
Net unamortized discount on debt												(9,053	)		(12,712	)
Long-term debt due within one year												(398,263	)		(466,589	)
Total long-term debt and long-term obligations												1,114,914			1,179,789
TOTAL CAPITALIZATION											$	3,708,793		$	3,862,829

*  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.

20

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

	Comprehensive Income			Number of Shares		Carrying Value		Accumulated Other Comprehensive Income (Loss)			Retained Earnings
	(Dollars in thousands)
Balance, January 1, 2002					100	$	2,098,729	$	--		$	572,272
Net income	$	356,159										356,159
Minimum liability for unfunded retirement benefits, net of $(45,525,000) of income taxes		(64,585	)						(64,585	)
Unrealized gain on investments, net of $3,582,000 of income taxes		5,090							5,090
Comprehensive income	$	296,664
Cash dividends on preferred stock												(6,510	)
Cash dividends on common stock												(121,900	)
Balance, December 31, 2002					100		2,098,729		(59,495	)		800,021
Net income	$	324,645										324,645
Minimum liability for unfunded retirement benefits, net of $2,014,000 of income taxes		2,674							2,674
Unrealized gain on investments, net of $12,337,000 of income taxes		18,128							18,128
Comprehensive income	$	345,447
Cash dividends on preferred stock												(2,732	)
Cash dividends on common stock												(599,000	)
Balance, December 31, 2003					100		2,098,729		(38,693	)		522,934
Net income	$	342,766										342,766
Minimum liability for unfunded retirement benefits, net of $(5,516,000) of income taxes		(7,552	)						(7,552	)
Unrealized loss on investments, net of $(533,000) of income taxes		(873	)						(873	)
Comprehensive income	$	334,341
Cash dividends on preferred stock												(2,502	)
Cash dividends on common stock												(421,000	)
Balance, December 31, 2004					100	$	2,098,729	$	(47,118	)	$	442,198

CONSOLIDATED STATEMENTS OF PREFERRED STOCK

	Not Subject to Mandatory Redemption						Subject to Mandatory Redemption
	Number of Shares			Par Value			Number of Shares			Par Value
	(Dollars in thousands)
Balance, January 1, 2002	5,000,699			$200,070			4,950,000			$135,000
Redemptions -
7.75%Series		(4,000,000	)		(100,000	)
9.00%Series								(4,800,000	)		(120,000	)
7.625%Series								(7,500	)		(750	)
Balance, December 31, 2002		1,000,699			100,070			142,500			14,250
Redemptions -
7.625%Series								(7,500	)		(750	)
Balance, December 31, 2003		1,000,699			100,070			135,000			13,500*
Redemptions -
7.625% Series								(7,500	)		(750	)
Balance, December 31, 2004		1,000,699		$	100,070			127,500		$	12,750*

*    The December 31, 2003 and 2004 balances for Preferred stock subject to mandatory redemption are classified as debt under SFAS 150.

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

21

OHIO 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	$	342,766		$	324,645		$	356,159
Adjustments to reconcile net income to net cash from operating activities:
Provision for depreciation		122,413			117,895			142,083
Amortization of regulatory assets		411,326			393,409			335,523
Deferral of new regulatory assets		(100,633	)		(73,183	)		(92,086	)
Nuclear fuel and lease amortization		42,811			39,317			47,597
Deferred lease costs		(5,170	)		(4,183	)		1,360
Deferred income taxes and investment tax credits, net		(44,469	)		(88,288	)		(75,719	)
Accrued retirement benefit obligations		31,289			47,524			18,069
Accrued compensation, net		4,551			(14,459	)		9,720
Cumulative effect of accounting change		--			(54,109	)		--
Pension trust contribution		(72,763	)		--			--
Decrease (increase) in operating assets:
Receivables		209,130			170,492			(41,584	)
Materials and supplies		(10,259	)		(2,038	)		(9,930	)
Prepayments and other current assets		1,286			(2,586	)		38,737
Increase (decrease) in operating liabilities:
Accounts payable		(80,738	)		132,983			182,229
Accrued taxes		(406,945	)		94,281			208,945
Accrued interest		(6,722	)		(9,495	)		(4,844	)
Other		(18,066	)		(12,221	)		(43,206	)
Net cash provided from operating activities		419,807			1,059,984			1,073,053
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		30,000			365,000			14,500
Short-term borrowings, net		--			--			161,836
Redemptions and Repayments-
Preferred stock		(750	)		(750	)		(220,750	)
Long-term debt		(170,997	)		(519,506	)		(425,742	)
Short-term borrowings, net		(4,015	)		(224,788	)		--
Dividend Payments-
Common stock		(421,000	)		(599,000	)		(121,900	)
Preferred stock		(2,502	)		(2,732	)		(6,510	)
Net cash used for financing activities		(569,264	)		(981,776	)		(598,566	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(235,022	)		(189,019	)		(148,967	)
Contributions to nuclear decommissioning trusts		(31,540	)		(31,540	)		(31,540	)
Loan repayments from (loans to) associated companies, net		128,054			66,401			(327,876	)
Proceeds from certificates of deposits		277,763			--			--
Other		9,549			57,321			49,820
Net cash provided from (used for) investing activities		148,804			(96,837	)		(458,563	)
Net increase (decrease) in cash and cash equivalents		(653	)		(18,629	)		15,924
Cash and cash equivalents at beginning of year		1,883			20,512			4,588
Cash and cash equivalents at end of year	$	1,230		$	1,883		$	20,512
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	65,765		$	103,632		$	118,535
Income taxes	$	419,123		$	250,564		$	126,558

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

22

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF TAXES

For the Years Ended December 31,	2004			2003			2002
	(In thousands)
GENERAL TAXES:
Ohio kilowatt-hour excise*	$	91,811		$	91,296		$	85,762
State gross receipts*		19,234			18,028			18,516
Real and personal property		58,000			51,074			65,709
Social security and unemployment		7,048			6,992			5,438
Other		4,430			2,688			1,596
Total general taxes	$	180,523		$	170,078		$	177,021
PROVISION FOR INCOME TAXES:
Currently payable-
Federal	$	246,865		$	270,345		$	280,587
State		75,907			81,505			55,796
		322,772			351,850			336,383
Deferred, net-
Federal		(23,668	)		(57,503	)		(44,552	)
State		(5,512	)		(16,038	)		(22,184	)
		(29,180	)		(73,541	)		(66,736	)
Investment tax credit amortization		(15,289	)		(14,747	)		(13,732	)
Total provision for income taxes	$	278,303		$	263,562		$	255,915
INCOME STATEMENT CLASSIFICATION OF PROVISION FOR INCOME TAXES:
Operating income	$	257,114		$	216,979		$	229,001
Other income		21,189			24,194			26,914
Cumulative effect of accounting change		--			22,389			--
Total provision for income taxes	$	278,303		$	263,562		$	255,915
RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES:
Book income before provision for income taxes	$	621,069		$	588,207		$	612,074
Federal income tax expense at statutory rate	$	217,374		$	205,872		$	214,225
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits		(15,289	)		(14,747	)		(13,732	)
State income taxes, net of federal income tax benefit		45,757			42,554			21,848
Amortization of tax regulatory assets		34,019			33,219			30,659
Other, net		(3,558	)		(3,336	)		2,915
Total provision for income taxes	$	278,303		$	263,562		$	255,915
ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31:
Property basis differences	$	451,269		$	406,783		$	397,930
Allowance for equity funds used during construction		27,730			30,493			34,407
Regulatory transition charge		154,015			345,723			527,502
Customer receivables for future income taxes		39,266			44,382			49,486
Deferred sale and leaseback costs		(63,432	)		(67,837	)		(71,830	)
Unamortized investment tax credits		(23,510	)		(29,031	)		(33,421	)
Deferred gain for asset sale to affiliated company		51,716			53,010			70,812
Other comprehensive income		(33,268	)		(27,219	)		(41,570	)
Retirement benefits		(6,202	)		(29,676	)		20,969
Shopping credit incentive deferral		94,002			57,731			32,476
All other		74,690			83,332			30,868
Net deferred income tax liability	$	766,276		$	867,691		$	1,017,629

* 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.

23

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION:

The consolidated financial statements include OE (Company) and its wholly owned subsidiaries. Penn is the Company's principal operating subsidiary. 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, TE, ATSI, JCP&L, Met-Ed and Penelec.

The Company and Penn (Companies) follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, PUCO, the PPUC and the FERC. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Certain 2003 revenues and expenses have been reclassified and presented on a net basis to conform with 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 Companies account for the effects of regulation through the application of SFAS 71 when their 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 Companies recognize, as regulatory assets, costs which the FERC, PUCO and PPUC have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered from customers under the Companies' respective transition and rate restructuring plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those operations.

24

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

	2004*			2003
	(In millions)
Regulatory transition costs	$	835		$	1,331
Customer shopping incentives		228			140
Customer receivables for future income taxes		99			115
Loss on reacquired debt		23			29
Employee postretirement benefit costs		2			6
Nuclear decommissioning costs		--			(72	)
Asset removal costs		(72	)		(72	)
Other		1			1
Total	$	1,116		$	1,478

* Changes in Penn's net regulatory asset components in 2004 resulted in net regulatory liabilities of approximately $18 million included in Other Noncurrent Liabilities on the Consolidated Balance Sheet as of December 31, 2004.

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 $228 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 - Ohio) using the effective interest method. Under the Rate Stabilization Plan, total transition cost amortization is expected to approximate the following for 2005 through 2007.

	(In millions)
2005	$	467
2006		193
2007		93

The decrease in amortization in 2006 results from the termination of generation-related transition cost recovery under the Ohio transition plan.

Accounting for Generation Operations-

The application of SFAS 71 was discontinued prior to 2001 with respect to the Companies' generation operations. The SEC's interpretive guidance regarding asset impairment measurement providing that any supplemental regulated cash flows such as a CTC should be excluded from the cash flows of assets in a portion of the business not subject to regulatory accounting practices. If those assets are impaired, a regulatory asset should be established if the costs are recoverable through regulatory cash flows. Consistent with the SEC guidance and EITF 97-4, $1.2 billion of impaired plant investments were recognized by the Company as regulatory assets recoverable as transition costs through future regulatory cash flows and $227 million were recognized for Penn related to its 1998 impairment of its nuclear generating unit investments to be recovered through a CTC over a seven-year transition period.

Net assets included in utility plant relating to the operations for which the application of SFAS 71 was discontinued, compared to the respective company's total assets as of December 31, 2004 were $1.059 billion and $5.8 billion, respectively, for the Company and $263 million and $921 million, respectively, for Penn.

(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.

25

(C) REVENUES AND RECEIVABLES-

The Companies' principal business is providing electric service to customers in Ohio and Pennsylvania. The Companies' 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 Companies accrue the estimated unbilled amount receivable as revenue and reverse the related prior period estimate.

Receivables from customers include sales to residential, commercial and industrial customers 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 Companies' customers. Total customer receivables were $274 million (billed - $172 million and unbilled - $102 million) and $281 million (billed - $165 million and unbilled - $116 million) as of December 31, 2004 and 2003, respectively.

(D) UTILITY PLANT AND DEPRECIATION-

Utility plant reflects original cost of construction (except for the Companies' 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 Companies' accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred.

The Companies provide for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annual composite rate for the Company's electric plant was approximately 2.3% in 2004, 2.2% in 2003 and 2.4% in 2002. The annual composite rate for Penn's electric plant was approximately 2.2% in 2004 and 2003 and 2.3% in 2002.

Jointly - Owned Generating Stations-

The Companies, together with CEI and TE, 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 Companies’ portions of operating expenses associated with jointly - owned facilities are 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:

							Companies’
	Utility		Accumulated		Construction		Ownership/
	Plant		Provision for		Work in		Leasehold
Generating Units	in Service		Depreciation		Progress		Interest
	(In millions)
W. H. Sammis Unit 7	$	335	$	173	$	--		68.80	%
Bruce Mansfield Units 1, 2 and 3		989		549		--		67.18	%
Beaver Valley Units 1 and 2		230		40		160		77.81	%
Perry		364		357		9		35.24	%
Total	$	1,918	$	1,119	$	169

Asset Retirement Obligations-

The Company recognizes a liability for retirement obligations associated with tangible assets in accordance with SFAS 143. This standard 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 value of the long-lived asset and depreciated over time, as described further in Note 10, "Asset Retirement Obligations".

Nuclear Fuel-

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

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(E) ASSET IMPAIRMENTS-

Long-Lived Assets-

The Companies evaluate the carrying value of their 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.

Investments-

The Companies periodically evaluate for impairment investments that include available-for-sale securities held by their 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 Companies consider, 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 Companies' investments are disclosed in Note 5.

(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, AOCL consisted of a minimum liability for unfunded retirement benefits of $69 million and unrealized gains on investments in securities available for sale of $22 million. As of December 31, 2003, accumulated other comprehensive loss consisted of a minimum liability for unfunded retirement benefits of $62 million and unrealized gains on investments in securities available for sale of $23 million.

(G) CUMULATIVE EFFECT OF ACCOUNTING CHANGE-

Upon adoption of SFAS 143 in the first quarter of 2003, OE recorded an after-tax credit to net income of $32 million. The cumulative adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $54 million increase to income, or $32 million net of income taxes.

(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 Companies are included in FirstEnergy's consolidated federal income tax return. The consolidated tax liability is allocated on a "stand-alone" company basis, with the Companies recognizing any tax losses or credits they contribute 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 Companies, CEI and TE. As a result, the Companies entered into power supply agreements (PSA) whereby FES purchases all of the Companies' nuclear generation and the Companies purchase their power from FES to meet their "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.

The primary affiliated companies transactions are as follows:

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	2004		2003		2002
	(In millions)
Operating Revenues:
PSA revenues from FES	$	416	$	384	$	329
Generating units rent from FES		178		178		178
Ground lease with ATSI		12		12		12
Operating Expenses:
Purchased power under PSA		970		902		912
Transmission expense		--		65		85
FESC support services		91		116		141
Other Income:
Interest income from ATSI		16		16		16
Interest income from FES		9		12		12

FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Companies 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 certain amounts due from FirstEnergy related to the formation of the holding company ($61 million) and receivables from affiliates for OPEB obligations ($17 million).

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 (Companies' share was $73 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 (Companies' share was $44 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	)
Companies' share of net amount recognized	$	118		$	53		$	(272	)	$	(249	)
Increase (decrease) in minimum liability included in other comprehensive income (net of tax)	$	(4	)	$	(145	)		--			--
Assumptions Used to Determine Benefit Obligations As of December 31
Discount rate		6.00	%		6.25	%		6.00	%		6.25	%
Rate of compensation increase		3.50	%		3.50	%
Allocation of Plan Assets As of December 31
Asset Category
Equity securities		68	%		70	%		74	%		71	%
Debt securities		29			27			25			22
Real estate		2			2			--			--
Cash		1			1			1			7
Total		100	%		100	%		100	%		100	%

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

Components of Net Periodic Benefit Costs	Pension Benefits									Other Benefits
	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
Companies' share of net periodic cost	$	7		$	24		$	3		$	28		$	43		$	15
Weighted-Average Assumptions Used
to Determine Net Periodic Benefit Cost	Pension Benefits									Other Benefits
for Years Ended December 31		2004			2003			2002			2004			2003			2002
Discount rate		6.25	%		6.75	%		7.25	%		6.25	%		6.75	%		7.25	%
Expected long-term return on plan assets		9.00	%		9.00	%		10.25	%		9.00	%		9.00	%		10.25	%
Rate of compensation increase		3.50	%		3.50	%		4.00	%

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

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

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

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

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	1-Percentage- Point Increase		1-Percentage- 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 Companies’ postretirement benefit costs by $14 million during 2004.

Consistent with the guidance in FSP 106-2 issued on May 19, 2004, FirstEnergy recognized a reduction of $318 million in the accumulated postretirement benefit obligation as a result of the federal subsidy provided under the Medicare Act related to benefits for past service. This reduction was accounted for as an actuarial gain in 2004 pursuant to FSP 106-2.The subsidy reduced the Companies’ net periodic postretirement benefit costs by $11 million during 2004.

As a result of their voluntary contribution and the increased market value of pension plan assets, the Companies reduced their accrued benefit cost as of December 31, 2004 by $48 million. As prescribed by SFAS 87, the Companies increased their additional minimum liability by $18 million, recording an increase in an intangible asset of $5 million and debiting OCI by $13 million. The balance in AOCL of $69 million (net of $49 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.   ESOP:

An ESOP Trust funds most of the matching contribution for FirstEnergy's 401(k) savings plan. All full-time employees eligible for participation in the 401(k) savings plan are covered by the ESOP. The ESOP borrowed $200 million from OE and acquired 10,654,114 shares of OE's common stock (subsequently converted to FirstEnergy common stock) through market purchases. Dividends on ESOP shares are used to service the debt. Shares are released from the ESOP on a pro rata basis as debt service payments are made. As of December 31, 2004, the Company had an approximately $61 million receivable from FirstEnergy representing reductions to the outstanding loan balance from the ESOP Trust that were paid to FirstEnergy since 1998 that were intended to be remitted to the Company; that receivable will be paid in December 2005.

5. FAIR VALUE OF FINANCIAL INSTRUMENTS:

Long-term Debt and Other Long-term Obligations-

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

	2004				2003
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Long-term debt	$	1,504	$	1,528	$	1,639	$	1,677
Preferred stock subject to mandatory redemption		13		12		14		14
	$	1,517	$	1,540	$	1,653	$	1,691

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The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by a corporation with credit ratings similar to the Companies' 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	$	137	$	137	$	126	$	126
-Corporate debt securities (2)		609		708		1,063		1,126
-Mortgage-backed securities		1		1		--		--
		747		846		1,189		1,252
Equity securities (1)		289		289		260		260
	$	1,036	$	1,135	$	1,449	$	1,512

⁽¹⁾ Includes nuclear decommissioning trust investments.

⁽²⁾ Includes investments in lease obligation bonds (see Note 6).

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

Investments other than cash and cash equivalents include held-to-maturity securities and available-for-sale securities. Decommissioning trust investments are classified as available-for-sale. The Companies have 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	$	186	$	3	$	1	$	188	$	164	$	4	$	--	$	168
Equity securities		205		49		6		248		165		52		9		208
	$	391	$	52	$	7	$	436	$	329	$	56	$	9	$	376

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	$	154	$	189	$	125
Gross realized gains		25		10		4
Gross realized losses		7		5		8
Interest and dividend income		13		10		9

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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 Value		Unrealized Losses		Fair Value		Unrealized Losses		Fair Value		Unrealized Losses
	(In millions)
Debt securities	$	64	$	1	$	5	$	--	$	69	$	1
Equity securities		12		2		28		4		40		6
	$	76	$	3	$	33	$	4	$	109	$	7

The Companies periodically evaluate the securities held by their nuclear decommissioning trusts for other-than-temporary impairment. The Companies consider 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. Penn's decommissioning trusts are subject to regulatory accounting in accordance with SFAS 71. Net unrealized gains and losses are recorded as regulatory liabilities or assets since the difference 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.

6.   LEASES:

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

The Company sold portions of its ownership interest in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on the portions sold for basic lease terms of approximately 29 years. During the terms of the leases, the Company continues to be responsible, to the extent of its individual combined ownership and leasehold interests, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. The Company has the right, at the end of the respective basic lease terms, to renew the leases for up to two years. The Company also has 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. The basic rental payments are adjusted when applicable federal tax law changes.

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	$	94.1	$	96.4	$	100.9
Other		47.1		41.2		34.6
Capital leases
Interest element		1.0		1.7		1.6
Other		1.6		1.4		1.3
Total rentals	$	143.8	$	140.7	$	138.4

33

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

			Operating Leases
					PNBV
	Capital		Lease		Capital
	Leases		Payments		Trusts		Net
	(In millions)
2005	$	4.3	$	138.8	$	56.6	$	82.2
2006		4.3		139.9		59.5		80.4
2007		0.3		139.3		59.9		79.4
2008		0.3		139.6		34.9		104.7
2009		0.3		140.1		42.1		98.0
Years thereafter		1.3		992.9		279.4		713.5
Total minimum lease payments		10.8	$	1,690.6	$	532.4	$	1,158.2
Executory costs		3.7
Net minimum lease payments		7.1
Interest portion		1.8
Present value of net minimum lease payments		5.3
Less current portion		1.9
Noncurrent portion	$	3.4

The Company invested in the PNBV Capital Trust, which was established to purchase a portion of the lease obligation bonds issued on behalf of lessors in the Company’s Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. The PNBV capital trust arrangement effectively reduces lease costs related to those transactions. OE has LOCs of $294 million and $154 million in connection with the sale and leaseback of Beaver Valley Unit 2 and Perry Unit 1, respectively.

7.   VARIABLE INTEREST ENTITIES:  

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

Included in the Company’s consolidated financial statements is PNBV, a VIE created in 1996 to refinance debt originally issued in connection with sale and leaseback transactions.

PNBV was established to purchase a portion of the lease obligation bonds issued in connection with the Company's 1987 sale and leaseback of its interests in the Perry Plant and Beaver Valley Unit 2. The Company used debt and available funds to purchase the notes issued by PNBV. Ownership of PNBV includes a three-percent equity interest by a nonaffiliated third party and a three-percent equity interest held by OES Ventures, a wholly owned subsidiary of the Company. As required by FIN 46R, consolidation of PNBV as of December 31, 2003 changed the previously reported trust investment of $361 million to an investment in collateralized lease bonds of $372 million. The $11 million increase represented the minority interest in the total assets of PNBV.

Through its investment in PNBV, the Company has variable interests in certain owner trusts that acquired the interests in the Perry Plant and Beaver Valley Unit 2. The Company has concluded that it was not the primary beneficiary of the owner trusts and was therefore not required to consolidate these entities. The leases are accounted for as operating leases in accordance with GAAP.

The Company is exposed to losses under the sale-leaseback agreements upon the occurrence of certain contingent events that it considers unlikely to occur. The Company has a maximum exposure to loss under these provisions of approximately $1 billion, which represents the net amount of casualty value payments upon the occurrence of specified casualty events that render the applicable plant worthless. Under the sale and leaseback agreement, the Company has net minimum discounted lease payments of $673 million that would not be payable if the casualty value payments are made.

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

On January 16, 2004, the PPUC initiated a formal investigation of whether Met-Ed's, Penelec's and Penn's “service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring” in Pennsylvania. Hearings were held in early August 2004. On September 30, 2004, Met-Ed, Penelec and Penn filed a settlement agreement with the PPUC that addresses the issues related to this investigation. As part of the settlement, Met-Ed, Penelec and Penn agreed to enhance service reliability, ongoing periodic performance reporting and communications with customers and to collectively maintain their current spending levels of at least $255 million annually on combined capital and operation and maintenance expenditures for transmission and distribution for the years 2005 through 2007. The settlement also outlines an expedited remediation process to address any alleged non-compliance with terms of the settlement and an expedited PPUC hearing process if remediation is unsuccessful. On November 4, 2004, the PPUC accepted the recommendation of the ALJ approving the settlement.

Ohio-

In October 2003, OE 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 OE's transition plan market development period. On February 24, 2004, OE 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, OE accepted the Rate Stabilization Plan as modified and approved by the PUCO on August 4, 2004. In the second quarter of 2004, OE 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.

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

· extension of the amortization period for transition costs being recovered through the RTC from 2006 to as late as 2007;

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

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

On December 9, 2004, the PUCO rejected the auction price results from a required competitive bid process and issued an entry stating that the pricing under the approved revised Rate Stabilization Plan will take effect on January 1, 2006. The PUCO may cause OE to undertake, no more often than annually, a similar competitive bid process to secure generation for the years 2007 and 2008. Any acceptance of future competitive bid results would terminate the Rate Stabilization Plan pricing, but not the related approved accounting.

On December 30, 2004, OE filed an application with the PUCO seeking tariff adjustments to recover increases of approximately $14 million in transmission and ancillary service costs beginning January 1, 2006. OE also filed an application for authority to defer costs associated with MISO Day 1, MISO Day 2, congestion fees, FERC assessment fees, and the ATSI rate increase, as applicable, from October 1, 2003 through December 31, 2005. Various parties have intervened in these cases.

Pennsylvania-

Pennsylvania enacted its electric utility competition law in 1996 with the phase-in of customer choice for generation suppliers completed as of January 1, 2001. In 1998, the PPUC authorized a rate restructuring plan for Penn, which essentially resulted in the deregulation of Penn’s generation business. Under the rate restructuring plan, Penn is entitled to recover $236 million of stranded costs through the CTC that began in 1999 and ends in 2006.

9.   CAPITALIZATION:

(A)   RETAINED EARNINGS-

Under the Company’s first mortgage indenture, the Company’s consolidated retained earnings unrestricted for payment of cash dividends on the Company’s common stock were $438.2 million as of December 31, 2004.

(B)   PREFERRED AND PREFERENCE STOCK-

All preferred stock may be redeemed by the Companies in whole, or in part, with 30-60 days’ notice.

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

Preferred Stock Subject To Mandatory Redemption-

Penn's 7.625% series has an annual sinking fund requirement for 7,500 shares in 2005 and 2006.

The Companies’ preferred shares are retired at $100 per share plus accrued dividends. Annual sinking fund requirements are approximately $750,000 in 2005 and 2006 and $11.25 million in 2007.

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

Other Long-term Debt-

Each of the Companies 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 also has a 1998 general mortgage under which it issues mortgage bonds based upon the pledge of a like amount of first mortgage bonds as security. These mortgage bonds therefore effectively enjoy the same lien on that property. The Companies have various debt covenants under their respective financing arrangements. The most restrictive of their 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 exists cross-default provisions among financing arrangements of FirstEnergy and the Companies.

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Based on the amount of FMB authenticated by the respective mortgage bond trustees through December 31, 2004, the Companies' annual sinking fund requirements for all FMB issued under the various mortgage indentures amounts to $40 million. The Companies expect to deposit funds with their respective mortgage bond trustees in 2005 that will then be withdrawn upon the surrender for cancellation of a like principal amount of FMB, specifically authenticated for such purposes against unfunded property additions or against previously retired FMB. This method can result in minor increases in the amount of the annual sinking fund requirement.

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

	(In millions)
2005	$	396
2006		6
2007		6
2008		229
2009		2

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. These amounts are $261 million and $50 million in 2005 and 2008, respectively, representing the next time the debt holders may exercise this provision.

The Companies' obligations to repay certain pollution control revenue bonds are secured by several series of FMB. Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank LOCs of $168.5 million and noncancelable municipal bond insurance policies of $449.8 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the LOCs or the policies, the Companies are entitled to a credit against their obligation to repay those bonds. The Companies pay annual fees of 1.0% to 1.7% of the amounts of the LOCs to the issuing banks and are 0.20% to 0.55% of the amounts of the policies to the insurers and are obligated to reimburse the banks or insurers, as the case may be, for any drawings thereunder.

The Company had no unsecured borrowings as of December 31, 2004 under a $250 million long-term revolving credit facility agreement which expires May 12, 2005. The Company currently pays an annual facility fee of 0.20% on the total credit facility amount. The Company had no unsecured borrowings as of December 31, 2004 under a $125 million long-term revolving credit facility which expires October 23, 2006. The Company currently pays an annual facility fee of 0.25% on the total credit facility amount. The fees are subject to change based on changes to the Company's credit ratings.

OES Finance, Incorporated, a wholly owned subsidiary of the Company, had maintained certificates of deposits pledged as collateral to secure reimbursement obligations relating to certain LOCs supporting the Company's obligations to lessors under the Beaver Valley Unit 2 sale and leaseback arrangements. In June 2004, these LOCs were replaced by a new LOC which did not require the collateral deposits. The Company entered into a Credit Agreement pursuant to which a standby LOC was issued in support of the replacement LOCs and the issuer of the standby LOC obtained the right to pledge or assign participations in the Company's reimbursement obligations to a trust. The trust then issued and sold trust certificates to institutional investors that were designed to be the credit equivalent of an investment directly in the Company. The certificates of deposit were cancelled and the Company received cash proceeds of $278 million in the third quarter of 2004.

10.   ASSET RETIREMENT OBLIGATIONS:

In January 2003, the Companies 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 asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize a regulatory asset or liability instead of an expense if the criteria for such treatment are met. Upon retirement, a gain or loss would be recognized if the cost to settle the retirement obligation differs from the carrying amount.

The Companies 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 $297.6 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. Accretion was $21 million and $20 million during 2004 and 2003, respectively, bringing the ARO liability as of December 31, 2004 to $339 million. The ARO includes the Companies' obligation for nuclear decommissioning of the Beaver Valley and Perry generating facilities. The Companies' share of the obligation to decommission these units was developed based on site specific studies performed by an independent engineer. The Companies utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO. The Companies maintain nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of December 31, 2004, the fair value of the decommissioning trust assets was $436 million.

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

Effect of the Change in Accounting Principle Applied Retroactively
	2002
	(In millions)
Reported net income	$	356
Increase (Decrease):
Elimination of decommissioning expense		30
Depreciation of asset retirement cost		(1	)
Accretion of ARO liability		(11	)
Non-regulated generation cost of removal component, net		5
Income tax effect		(9	)
Net earnings increase		14
Net income adjusted	$	370

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	$	318	$	298
Accretion		21		20
Ending balance as of December 31	$	339	$	318

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	$	279
Accretion		19
Ending balance as of December 31	$	298

11.   SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT:

Short-term borrowings outstanding as of December 31, 2004, consisted of $25 million of OE bank borrowings and $142 million of OES Capital, Incorporated borrowings. OES Capital is a wholly owned subsidiary of OE whose borrowings are secured by customer accounts receivable purchased from OE. OES Capital can borrow up to $170 million under a receivables financing arrangement at rates based on certain bank commercial paper and is required to pay an annual fee of 0.25% on the amount of the entire finance limit. The receivables financing agreement expires in October 2005. Penn has, through a wholly owned subsidiary, a receivables financing arrangement that provides a combined borrowing capability of up to $11.9 million at rates based on bank commercial paper rates. The financing arrangements require payment of an annual facility fee of 0.40% on the entire finance limit. Penn's receivables financing agreements expire in March 2005 and is expected to be renewed prior to expiration.

OE has various bi-lateral credit facilities with domestic banks that provide for borrowings of up to $34 million under various interest rate options. To assure the availability of these lines, OE is required to pay annual commitment fees that vary from 0.20% to 0.25% of total lender commitments. These lines expire at various times during 2005. The weighted average interest rates on short-term borrowings outstanding as of December 31, 2004 and 2003 were 2.28% and 1.16%, 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 their ownership and leasehold interests in the Beaver Valley Station and the Perry Plant, the Companies' 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 $192.0 million per incident but not more than $19.1 million in any one year for each incident.

The Companies are also insured as to their respective interests in Beaver Valley 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 Companies have also obtained approximately $677.3 million of insurance coverage for replacement power costs for their respective interests in Beaver Valley and Perry. Under these policies, the Companies can be assessed a maximum of approximately $32 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 Companies intend 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 Companies' 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 Companies' insurance policies, or to the extent such insurance becomes unavailable in the future, the Companies would remain at risk for such costs.

(B)   ENVIRONMENTAL MATTERS-

Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. The effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on the Companies' earnings and competitive position. These environmental regulations affect the Companies' earnings and competitive position to the extent that they compete 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 Companies believe they are in material compliance with existing regulations but are 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 Companies are required to meet federally approved SO₂ regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $32,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

The Companies believe they are complying with SO₂ reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NO_x reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NO_x reductions from the Companies' facilities. The EPA's NO_x Transport Rule imposes uniform reductions of NO_x emissions (an approximate 85% 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 NOx emissions are contributing significantly to ozone levels in the eastern United States. The Companies believe their facilities are complying with the NO_x budgets established under State Implementation Plans (SIPs) through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.

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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" NO_x and SO₂ emissions in two phases (Phase I in 2010 and Phase II in 2015). According to the EPA, SO₂ emissions would be reduced by approximately 3.6 million tons annually by 2010, across states covered by the rule, with reductions ultimately reaching more than 5.5 million tons annually. NO_x emission reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in 2015. The future cost of compliance with these proposed regulations may be substantial and will depend on whether and how they are ultimately implemented by the states in which the Companies operate affected facilities.

Mercury Emissions-

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On 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.

W. H. Sammis Plant-

In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities covering 44 power plants, including the W. H. Sammis Plant, which is owned by the Company and Penn. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against the Company and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase of the trial to address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant has been delayed without rescheduling by the Court because the parties are engaged in meaningful settlement negotiations. The Court indicated, in its August 2003 ruling, that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact on the Companies' financial condition and results of operations. While the parties are engaged in meaningful settlement discussions, management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of December 31, 2004.

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.

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Climate Change-

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

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

Clean Water Act-

Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to the Companies' plants. In addition, Ohio, and Pennsylvania have water quality standards applicable to the Companies' operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio 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 Companies are conducting comprehensive demonstration studies, due in 2008, to determine the operational measures, equipment or restoration activities, if any, necessary for compliance by their facilities with the performance standards. FirstEnergy is unable to predict the outcome of such studies. Depending on the outcome of such studies, the future cost of compliance with these standards may require material capital expenditures.

(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, and ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which are consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy certified to NERC on June 30, 2004, completion of various reliability recommendations and further received independent verification of completion status from a NERC verification team on July 14, 2004 with minor exceptions noted by FirstEnergy (see Note 8). FirstEnergy’s implementation of these recommendations included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these initiatives already were in process, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its operations or financial results. FirstEnergy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. FirstEnergy has not accrued a liability as of December 31, 2004 for any expenditures in excess of those actually incurred through that date.

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Three substantially similar actions were filed in various Ohio state courts by plaintiffs seeking to represent customers who allegedly suffered damages as a result of the August 14, 2003 power outages. All three cases were dismissed for lack of jurisdiction. One case was refiled at the PUCO. The other two cases were appealed. One case was dismissed and no further appeal was sought. The remaining case is pending. In addition to the one case that was refiled at the PUCO, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages.

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

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.

Legal Matters-

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

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 Companies have a 35.24% 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.

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 (the Company has no interest in Davis-Besse) has 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 the Company or its subsidiaries has legal liability or is otherwise made subject to liability based on any of the above matters, it could have a material adverse effect on the Company'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 Companies are currently evaluating this standard but do 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 Companies after June 30, 2005. The Companies are currently evaluating this standard but do 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 Companies 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 the Companies in the third quarter of 2004 and did not affect the Companies' 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 Companies' 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,		June 30,		September 30,		December 31,
Three Months Ended	2004		2004		2004		2004
	(In millions)
Operating Revenues	$	743.3	$	718.4	$	766.3	$	717.6
Operating Expenses and Taxes		660.9		632.2		670.8		646.2
Operating Income		82.4		86.2		95.5		71.4
Other Income		12.5		20.7		17.2		23.7
Net Interest Charges		18.8		19.5		10.0		18.6
Net Income	$	76.1	$	87.4	$	102.7	$	76.5
Earnings on Common Stock	$	75.5	$	86.7	$	102.1	$	76.0

	March 31,		June 30,		September 30,		December 31,
Three Months Ended	2003		2003		2003		2003
	(In millions)
Operating Revenues	$	742.8	$	673.7	$	774.7	$	734.1
Operating Expenses and Taxes		672.7		609.7		686.2		619.8
Operating Income		70.1		64.0		88.5		114.3
Other Income		13.5		15.4		15.9		22.0
Net Interest Charges		26.5		34.1		23.6		26.6
Income Before Cumulative Effect of Accounting Change		57.1		45.3		80.8		109.7
Cumulative Effect of Accounting Change (Net of Income Taxes)		31.7		--		--		--
Net Income	$	88.8	$	45.3	$	80.8	$	109.7
Earnings on Common Stock	$	88.1	$	44.7	$	80.1	$	109.0

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