METROPOLITAN EDISON COMPANY

2004 ANNUAL REPORT TO STOCKHOLDERS

Metropolitan Edison Company is a wholly owned electric utility subsidiary of FirstEnergy Corp. It engages in the distribution and sale of electric energy in eastern and south central Pennsylvania. The area it serves has a population of approximately 1.2 million.

Contents	Page
Glossary of Terms		i-ii
Management Reports		1
Report of Independent Registered Public Accounting Firm		2
Selected Financial Data		3
Management's Discussion and Analysis		4-13
Consolidated Statements of Income		14
Consolidated Balance Sheets		15
Consolidated Statements of Capitalization		16
Consolidated Statements of Common Stockholder's Equity		17
Consolidated Statements of Preferred Stock		17
Consolidated Statements of Cash Flows		18
Consolidated Statements of Taxes		19
Notes to Consolidated Financial Statements		20-36

GLOSSARY OF TERMS

The following abbreviations and acronyms are used in this report to identify Metropolitan 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, CEI, TE, Penn, JCP&L, Met-Ed and Penelec
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
GPU	GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on November 7, 2001
GPUS	GPU Service Company, previously provided corporate support services
JCP&L	Jersey Central Power & Light Company, an affiliated New Jersey electric utility
Met-Ed	Metropolitan Edison Company
MYR	MYR Group, Inc., a utility infrastructure construction service company
OE	Ohio Edison Company, an affiliated Ohio electric utility
Penelec	Pennsylvania Electric Company, an affiliated Pennsylvania electric utility
Penn	Pennsylvania Power Company, an affiliated Pennsylvania electric utility
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 25	APB Opinion No. 25, "Accounting for Stock Issued to Employees"
ARO	Asset Retirement Obligation
CTC	Competitive Transition Charge
ECAR	East Central Area Reliability Coordination
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
FIN 46R	FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities"
FMB	First Mortgage Bonds
FSP	FASB Staff Position
FSP EITF 03-1-1	FASB Staff Position No. EITF Issue 03-1-1, "Effective Date of Paragraphs 10-20 of EITF Issue No. 03-1, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments"
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"
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
Medicare Act	Medicare Prescription Drug, Improvement and Modernization Act of 2003
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service
NERC	North American Electric Reliability Council
NUG	Non-Utility Generation
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
PJM	PJM Interconnection L. L. C.
PLR	Provider of Last Resort

i

GLOSSARY OF TERMS, Cont'd

PPUC	Pennsylvania Public Utility Commission
PRP	Potentially Responsible Party
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act
RTC	Regulatory Transition Charge
S&P	Standard & Poor's Ratings Service
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 106	SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions"
SFAS 133	SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities"
SFAS 142	SFAS No. 142, "Goodwill and Other Intangible Assets"
SFAS 143	SFAS No. 143, "Accounting for Asset Retirement Obligations"
SFAS 144	SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"
SPE	Special Purpose Entity
TMI-1	Three Mile Island Unit 1
TMI-2	Three Mile Island Unit 2
VIE	Variable Interest Entity

ii

MANAGEMENT REPORTS

Management's Responsibility for Financial Statements

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

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

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

Management's Report on Internal Control Over Financial Reporting

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

1

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of Metropolitan Edison Company:

We have completed an integrated audit of Metropolitan 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 Metropolitan 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 6 to the consolidated financial statements, the Company changed its method of accounting for the consolidation of variable interest entities as of December 31, 2003.

Internal control over financial reporting

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

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

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

PricewaterhouseCoopers LLP

Cleveland, Ohio

March 7, 2005

2

METROPOLITAN EDISON COMPANY

SELECTED FINANCIAL DATA

	2004			2003			2002			Nov. 7 - Dec. 31, 2001			Jan. 1 - Nov. 6, 2001		2000
	(Dollars in thousands)
Operating Revenues	$	1,070,847		$	969,788		$	986,608		$	143,760			$         824,556	$	842,333
Operating Income	$	86,197		$	83,938		$	91,271		$	17,367			$         102,247	$	135,211
Income Before Cumulative Effect Of Accounting Change	$	66,955		$	60,953		$	63,224		$	14,617			$          62,381	$	81,895
Net Income	$	66,955		$	61,170		$	63,224		$	14,617			$          62,381	$	81,895
Total Assets	$	3,245,278		$	3,473,987		$	3,564,805		$	3,607,187				$	2,708,062
Capitalization as of December 31:
Common Stockholder’s Equity	$	1,285,419		$	1,292,667		$	1,315,586		$	1,288,953				$	537,013
Company-Obligated Trust Preferred Securities		--			--			92,409			92,200					100,000
Long-Term Debt and Other Long- Term Obligations		701,736			636,301			538,790			583,077					496,860
Total Capitalization	$	1,987,155		$	1,928,968		$	1,946,785		$	1,964,230				$	1,133,873
Capitalization Ratios:
Common Stockholder’s Equity		64.7	%		67.0	%		67.6	%		65.6	%				47.4	%
Company-Obligated Trust Preferred Securities		--			--			4.7			4.7					8.8
Long-Term Debt and Other Long- Term Obligations		35.3			33.0			27.7			29.7					43.8
Total Capitalization		100.0	%		100.0	%		100.0	%		100.0	%				100.0	%
Distribution Kilowatt-Hour Deliveries (Millions):
Residential		5,071			4,900			4,738			793			3,712		4,377
Commercial		4,251			4,034			3,991			652			3,203		3,699
Industrial		4,042			4,047			3,972			662			3,506		4,412
Other		33			36			35			6			27		38
Total		13,397			13,017			12,736			2,113			10,448		12,526
Customers Served:
Residential		464,287			455,073			448,334			442,763					436,573
Commercial		59,495			58,825			58,010			57,278					56,080
Industrial		1,868			1,906			1,936			1,961					1,967
Other		730			732			728			819					810
Total		526,380			516,536			509,008			502,821					495,430

3

METROPOLITAN 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, including by the Securities and Exchange Commission as disclosed in our Securities and Exchange Commission filings, the availability and cost of capital, 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 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.

Reclassifications

As discussed in Note 1 to the consolidated financial statements, certain prior year amounts have been reclassified to conform to the current year presentation. Revenue amounts related to transmission activities previously recorded as wholesale electric sales revenues were reclassified as transmission revenues. Expenses (including transmission and congestion charges) were reclassified among purchased power, other operating costs and amortization of regulatory assets to conform to the current year presentation. These reclassifications did not change previously reported net income in 2003 and 2002.

Results of Operations

Net income increased to $67 million in 2004, compared to $61 million in 2003, due to higher operating revenues partially offset by higher purchased power costs and other operating costs. Net income decreased to $61 million in 2003, compared to $63 million in 2002, due to lower operating revenues and increased operating expenses, including higher employee benefit costs and storm restoration expenses. These reductions to net income were partially offset by lower purchased power costs, principally due to reduced quantities of power purchased through two-party agreements. Net interest charges were lower in 2003 due to debt redemptions and the refinancing of higher-rate debt.

Operating revenues increased by $101 million in 2004, primarily as a result of increases of $31 million and $36 million in retail generation sales and distribution throughput revenues, respectively. The higher generation sales revenues reflect the effect of an 11.8% increase in sales volume partially offset by lower composite prices. The volume increase was due to 8.5% and 34.6% increases, respectively, in sales to the commercial and industrial sectors as a result of customers returning to us from alternate suppliers. Sales by alternative suppliers as a percent of total sales delivered in our franchise area decreased by 2.9 and 20.2 percentage points for commercial and industrial customers, respectively. Higher revenues of $36 million from electricity throughput in 2004 from 2003 were due to higher prices and a 2.9% increase in distribution deliveries. The higher volume reflected an increase in the retail customer base and an improving economy, partially offset by cooler weather in the summer months of 2004. The higher distribution prices were due to the PPUC Restructuring Settlement order (see Regulatory Matters) with a corresponding decrease in retail generation prices. Also contributing to the revenue increase was $34 million of PJM network transmission system revenue, Financial Transmission Rights (FTR)/Auction Revenue Rights (ARR), and PJM congestion credit revenues related to transmission transactions we assumed in 2004 due to a change in our power supply agreement with FES, which also increased transmission expenses by $51 million, as discussed below.

The significant decrease in customer shopping in 2004 reflects our low generation price as provider of last resort. Alternative suppliers have not been able to match that price by a sufficient margin to ensure profitability, particularly in the industrial sector.

4

Operating revenues decreased by $17 million in 2003, compared to 2002. The decrease in 2003 was the result of wholesale sales revenues decreasing $25 million principally due to a reduction in kilowatt-hour sales to affiliate companies and other wholesale customers. An increase in the number of commercial and industrial customers receiving their power from alternate suppliers also contributed to the decrease in operating revenues. Distribution deliveries benefited from higher demand by residential (3.4%), commercial (1.0%), and industrial (1.9%) customers due in large part to colder temperatures in early 2003, which were partially offset by milder summer weather.

Changes in kilowatt-hour sales by customer class are summarized in the following table:

Changes in Kilowatt-hour Sales	2004			2003
Increase (Decrease)
Electric Generation:
Retail		11.8	%		1.2	%
Wholesale		209.1	%		(100.0	)%
Total Electric Generation Sales		12.0	%		(6.1	)%
Distribution Deliveries:
Residential		3.5	%		3.4	%
Commercial		5.4	%		1.0	%
Industrial		(0.1	)%		1.9	%
Total Distribution Deliveries		2.9	%		2.2	%

Operating Expenses and Taxes

Total operating expenses and taxes increased $99 million or 11.2% in 2004 and decreased $9 million in 2003:

Operating Expenses and Taxes - Changes	2004			2003
Increase (Decrease)	(In millions)
Purchased power costs	$	64		$	(6	)
Other operating costs		32			3
Provision for depreciation		(3	)		(6	)
Amortization of regulatory assets		8			--
General taxes		3			--
Income taxes		(5	)		--
Total operating expenses and taxes	$	99		$	(9	)

Purchased power costs increased by $64 million in 2004, compared with 2003, primarily due to a 10.7% increase in kilowatt-hour purchases to meet higher retail generation sales requirements. Other operating costs increased by $32 million primarily due to PJM congestion and ancillary transmission expenses that we assumed in 2004 due to a change in our power supply agreement with FES. Depreciation expense decreased in 2004 due to fully depreciating the Energy Management System in 2003. Amortization of regulatory assets increased primarily due to higher regulatory asset amortization from higher revenue recovery of above market NUG costs in 2004. General taxes increased $3 million in 2004 primarily due to higher payroll and gross receipt taxes.

Total operating expenses and taxes decreased $9 million in 2003 compared to 2002. The majority of the decrease resulted from decreases in purchased power costs and depreciation expense, partially offset by higher other operating costs. Purchased power costs decreased by $6 million in 2003 because of reduced kilowatt hours required for customer needs during 2003, partially offset by slightly higher unit costs. The decrease in depreciation charges in 2003, compared to 2002, reflected a reduced depreciable asset base. Other operating costs increased in 2003 primarily due to increased costs to restore customer service resulting from significant storm activity and higher employee benefit costs.

Other Income

Other income increased $4 million in 2004, compared to 2003, due to a $2 million increase in the return on CTC stranded generation regulatory assets, and $2 million of interest income on federal income tax refunds.

Net Interest Charges

Interest on long-term debt increased by $4 million in 2004 as a result of increased debt outstanding from the issuance of $250 million of senior notes in the second quarter of 2004, partially offset by the retirement of $99 million of medium term notes and $100 million of preferred securities during the year. This increase was offset by a $4 million reduction in interest on company obligated manditorily redeemable preferred securities due to the redemption of all of the trust preferred securities in 2004.

5

Net interest charges decreased by $5 million in 2003, compared to 2002. The decrease reflects the refinancing of higher-cost debt in the first quarter of 2003.

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 $217,000. The cumulative effect adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $371,000 increase to income, or $217,000 net of income taxes.

Capital Resources and Liquidity

Our cash requirements in 2004 for operating expenses, construction expenditures and scheduled debt maturities were met with a combination of cash from operations and funds from the capital markets. During 2005 and thereafter, we expect to meet our contractual obligations with a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

As of December 31, 2004, we had $120,000 of cash and cash equivalents compared with $121,000 as of December 31, 2003. The major sources for changes in these balances are summarized below.

Cash Flows From Operating Activities

Cash flows provided from operating activities totaled $74 million in 2004, $132 million in 2003 and $102 million in 2002. The sources of these changes are as follows:

Operating Cash Flows	2004			2003			2002
	(In millions)
Cash earnings (1)	$	151		$	180		$	146
Pension trust contribution(2)		(23	)		--			--
Working capital		(54	)		(48	)		(44	)
Total	$	74		$	132		$	102

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

⁽²⁾ Pension trust contribution net of $16 million of income tax benefits.

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

Reconciliation of Cash Earnings	2004			2003			2002
	(In millions)
Net Income (GAAP)	$	67		$	61		$	63
Non-Cash Charges (Credits):
Provision for depreciation		41			44			51
Amortization of regulatory assets		106			98			98
Deferred costs recoverable as regulatory assets		(66	)		(71	)		(86	)
Deferred income taxes and investment tax credits		3			46			23
Other non-cash expenses		--			2			(3	)
Cash earnings (Non-GAAP)	$	151		$	180		$	146

Net cash provided from operating activities decreased $58 million during 2004, compared with 2003. The decrease consisted of lower cash earnings of $29 million, a $23 million after-tax voluntary pension trust contribution in 2004, and a $6 million decrease from changes in working capital. The decrease in cash earnings reflects changes in deferred income tax expense partially offset by other changes as described under "Results of Operations". The decrease in working capital was principally due to changes in receivables partially offset by increases in accounts payable balances. Net cash from operating activities increased by $30 million in 2003 compared to 2002 due to a $34 million increase in cash earnings partially offset by a $4 million decrease in working capital. The increase in cash earnings reflects changes in deferred income tax expense; the working capital decrease primarily reflected changes in receivables partially offset by changes in accrued tax balances.

6

Cash Flows From Financing Activities

In 2004, net cash provided from financing activities was $11 million, including $247 million in proceeds from the issuance of unsecured senior notes during the first quarter of 2004, and $15 million in short-term borrowings. The new financing was partially offset by the redemption of $100 million of unsecured subordinated debentures, $90 million of redeemed first mortgage bonds, redemption of $6 million of other unsecured obligations, and $55 million of common stock dividend payments.

In 2003, net cash used for financing activities of $88 million reflects redemptions of long-term debt of $260 million, repayment of $23 million of short-term borrowings, and $52 million of common stock dividend payments to FirstEnergy, partially offset by $248 million in proceeds from the issuance of secured notes. In 2002, net cash used for financing activities of $54 million reflects redemption of $60 million debt and $60 million of common stock dividend payments to FirstEnergy, partially offset by $50 million in proceeds from the issuance of secured notes, and a $16 million increase in short-term borrowings.

The following table provides details regarding new issues and redemptions during each year:

Securities Issued or Redeemed	2004		2003			2002
New Issues
Secured notes	$	--	$	248		$	50
Unsecured notes		247		--			--
Redemptions
First Mortgage Bonds	$	90	$	260		$	60
Subordinated Debentures		100		--			--
Other - Cowanesque		6		--			--
	$	196	$	260		$	60
Short-term Borrowings, net source /(use) of cash	$	15	$	(23	)	$	16

In March 2004, we completed a receivables financing arrangement that provides borrowings of up to $80 million. The borrowing rate is based on bank commercial paper rates. We are required to pay an annual facility fee of 0.30% on the entire finance limit. The facility was undrawn as of December 31, 2004 and matures on March 29, 2005. We plan to renew the agreement.

We have $80 million of short-term indebtedness at the end of 2004, compared to $65 million at the end of 2003. We have obtained authorization from the SEC to incur short-term debt up to $250 million (including the utility money pool). Under the terms of our senior note indenture, we are no longer permitted to issue FMB so long as senior notes are outstanding. These receivables financing arrangements are expected to be renewed prior to expiration.

We have the ability to borrow from our regulated affiliates and FirstEnergy to meet our short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of such 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%.

Our  access to capital  markets and costs of financing are dependent on the ratings of our securities  and that of FirstEnergy. On August 26, 2004, S&P lowered its rating on certain of our Senior Notes to BBB- from BBB. The rationale for the ratings change was that our senior secured notes, in aggregate, now comprise greater than 80% of our total debt outstanding. According to the terms of the senior note indenture, once the 80% threshold is reached, the collateral mortgage bond security falls away and all senior secured notes that were secured by our senior note indenture become unsecured. The one notch lower rating reflects this loss of collateral security. The BBB senior secured rating on our first mortgage bonds remained unchanged.

7

The following table shows the securities ratings as of December 31, 2004. The ratings outlook from the ratings agencies on all securities is stable.

Ratings of Securities
	Securities	S&P	Moody’s	Fitch
FirstEnergy	Senior unsecured	BB+	Baa3	BBB-
Met-Ed	Senior secured	BBB	Baa1	BBB+
	Senior unsecured	BBB-	Baa2	BBB

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

Cash used for investing activities totaled $85 million in 2004 and $60 million in 2003. The increase resulted from a $10 million increase in property additions, $1 million of additional loans to associated companies, and a $9 million capital transfer from FESC.

Cash used for investing activities totaled $60 million in 2003 and $58 million in 2002. The net cash flows used for investing activities during 2003 resulted from property additions, decommissioning trust investments, and loans to associated companies. Cash used for investing activities during 2002 were for property additions primarily to support our energy delivery operations and decommissioning trust investments.

Our capital spending for the period 2005 through 2007 is expected to be about $205 million for property additions and energy delivery related improvements, of which approximately $67 million applies to 2005.

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 (3)	$	730	$	30	$	151	$	7	$	542
Short-term borrowings		80		80		--		--		--
Operating leases (1)		49		1		3		3		42
Purchases (2)		2,922		309		804		745		1,064
Total	$	3,781	$	420	$	958	$	755	$	1,648

⁽¹⁾ Operating lease payments are net of reimbursements from sublessees (see Note 5 - Leases)

⁽²⁾ Power purchases under contracts with fixed or minimum quantities and approximate timing

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

Market Risk Information

We use various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. Our Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughout our Company. They are responsible for promoting the effective design and implementation of sound risk management programs. They also oversee compliance with corporate risk management policies and established risk management practices.

8

Commodity Price Risk

We are exposed to market risk primarily due to fluctuations in electricity, natural gas, coal, nuclear fuel and emission allowance prices. To manage the volatility relating to these exposures, we use a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes and, to a much lesser extent, for trading purposes. Most of our non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. The change in the fair value of commodity derivative contracts related to energy production during 2004 is summarized in the following table:

Increase in the Fair Value of Derivative Contracts	Non-Hedge		Hedge		Total
	(In millions)
Change in the fair value of commodity derivative contracts
Outstanding net asset as of January 1, 2004	$	31	$	--	$	31
New contract value when entered		--		--		--
Additions/Increase in value of existing contracts		1		--		1
Change in techniques/assumptions		--		--		--
Settled contracts		--		--		--
Net Assets - Derivatives Contracts as of December 31, 2004 (1)	$	32	$	--	$	32
Impact of Changes in Commodity Derivative Contracts (2)
Income Statement Effects (Pre-Tax)	$	1	$	--	$	1
Balance Sheet Effects:
OCI (Pre-Tax)	$	--	$	--	$	--

⁽¹⁾ Includes $31 million in non-hedge commodity derivative contracts, which are offset by a regulatory liability.

⁽²⁾ Represents the increase in value of existing contracts, settled contracts and changes in techniques/ assumptions.

Derivatives are included on the Consolidated Balance Sheet as of December 31, 2004 as follows:

	Non-Hedge		Hedge		Total
	(In millions)
Current-
Other Assets	$	--	$	--	$	--
Other liabilities		--		--		--
Non-Current-
Other Deferred Charges		32		--		32
Other noncurrent liabilities		--		--		--
Net assets	$	32	$	--	$	32

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, we rely on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. We use these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts by year are summarized in the following table:

Source of Information - Fair Value by Contract Year	2005		2006		2007		2008		Thereafter		Total
	(In millions)
Other external sources (1)		10		4		--		--		--		14
Prices based on models		--		--		6		5		7		18
Total(2)	$	10	$	4	$	6	$	5	$	7	$	32

(1) Broker quote sheets.

⁽²⁾   Includes $31 million from an embedded option that is offset by a regulatory liability and does not affect earnings.

9

We perform sensitivity analyses to estimate our exposure to the market risk of our commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on both our trading and nontrading derivative instruments would not have had a material effect on our consolidated financial position or cash flows as of December 31, 2004. We estimate that if energy commodity prices experienced an adverse 10% change, net income for the next twelve months would not change, as the prices for all commodity positions are already above the contract price caps.

Interest Rate Risk

We are subject to the inherent interest rate risks related to refinancing maturing debt by issuing new debt securities. Our exposure to fluctuations in market interest rates is reduced since our debt has fixed interest rates, as noted in the following table.

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														$	83		$	83		$	83
Average interest rate															4.7	%		4.7	%
Liabilities
Long-term Debt and Other Long-Term Obligations:
Fixed rate	$	30		$	101		$	50		$	7			$	542		$	730		$	731
Average interest rate		6.8	%		5.7	%		5.9	%		6.0	%			4.9	%		5.2	%
Short-term Borrowings		80															$	80		$	80
Average interest rate		2.0	%															2.0	%

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $134 million and $114 million as of December 31, 2004 and 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $13 million reduction in fair value as of December 31, 2004 (see Note 4 - Fair Value of Financial Instruments).

Outlook

Beginning in 1999, all of our customers were able to select alternative energy suppliers. We continue to deliver power to homes and businesses through our existing distribution system, which remains regulated. The PPUC authorized our rate restructuring plan, establishing separate charges for transmission, distribution, generation and stranded cost recovery, which is recovered through a CTC. Customers electing to obtain power from an alternative supplier have their bills reduced based on the regulated generation component, and the customers receive a generation charge from the alternative supplier. We have a continuing responsibility referred to as our PLR obligation to provide power to those customers not choosing to receive power from an alternative energy supplier, subject to certain limits.

We recognize, as regulatory assets, costs which the PPUC and the FERC 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 when incurred. All regulatory assets are expected to be recovered under the provisions of the regulatory plan. Our regulatory assets totaled $693 million and $1 billion as of December 31, 2004 and December 31, 2003, respectively.

Regulatory Matters

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

10

On January 12, 2005, we filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005 estimated to be approximately $4 million per month. Various parties have intervened in this case.

See Note 7 to the consolidated financial statements for a more complete and detailed discussion of regulatory matters in Pennsylvania.

Environmental Matters

We have been named as a PRP at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of December 31, 2004, based on estimates of the total costs of cleanup, our proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. We have accrued liabilities aggregating approximately $26,000 as of December 31, 2004.

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 above.

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.

Goodwill

In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, We evaluate goodwill for impairment at least annually and make such evaluations more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If an impairment were indicated, we would recognize a loss - calculated as the difference between the implied fair value of our goodwill and the carrying value of the goodwill. Our annual review was completed in the third quarter of 2004, with no impairment of goodwill indicated. The forecasts used in our evaluation of goodwill reflect operations consistent with our general business assumptions. Unanticipated changes in those assumptions could have a significant effect on our future evaluations of goodwill. In the year ended December 31, 2004, we adjusted goodwill related to interest received on a pre-merger income tax refund and for the reversal of tax valuation allowances related to income tax benefits realized attributable to prior period capital loss carryforwards that were used to offset capital gains generated in 2004. As of December 31, 2004, we had recorded goodwill of approximately $870 million.

Regulatory Accounting

We are subject to regulation that sets the prices (rates) it is permitted to charge its customers based on the costs that the regulatory agencies determine the company is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. 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.

11

Pension and Other Postretirement Benefits Accounting

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

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

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

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

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

In the third quarter of 2004, FirstEnergy made a $500 million voluntary contribution to its pension plan (our share was $39 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 $23 million. As prescribed by SFAS 87, we increased our additional minimum liability by $16 million, offset by a charge to OCI. The balance in AOCL of $42 million (net of $30 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.

Long-Lived Assets

In accordance with SFAS No. 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.

12

Nuclear Decommissioning

In accordance with SFAS 143, we recognize an ARO for the future decommissioning of TMI-2. 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 plant's current license and settlement based on an extended license term.

New Accounting Standards and Interpretations Adopted

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.

13

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME

	2004			2003			2002
	(In thousands)
OPERATING REVENUES (Note 2(I))	$	1,070,847		$	969,788		$	986,608
OPERATING EXPENSES AND TAXES:
Fuel and purchased power (Note 2(I))		554,988			491,346			497,163
Other operating costs (Note 2(I))		190,401			157,986			155,137
Provision for depreciation		41,161			44,160			50,838
Amortization of regulatory assets		105,675			97,784			97,957
General taxes		70,457			67,207			66,795
Income taxes		21,968			27,367			27,447
Total operating expenses and taxes		984,650			885,850			895,337
OPERATING INCOME		86,197			83,938			91,271
OTHER INCOME (NET OF INCOME TAXES)		25,537			21,782			21,742
NET INTEREST CHARGES:
Interest on long-term debt		40,630			36,657			40,774
Allowance for borrowed funds used during
construction		(278	)		(323	)		(470	)
Deferred interest		--			(1,187	)		( 710	)
Other interest expense		4,427			5,841			2,636
Subsidiary's preferred stock dividend requirements		--			3,779			7,559
Net interest charges		44,779			44,767			49,789
INCOME BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE		66,955			60,953			63,224
Cumulative effect of accounting change (net of income
taxes of $154,000) (Note 2(G))		--			217			--
NET INCOME	$	66,955		$	61,170		$	63,224

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

14

METROPOLITAN EDISON COMPANY

CONSOLIDATED BALANCE SHEETS

As of December 31,	2004		2003
	(In thousands)
ASSETS
UTILITY PLANT:
In service	$	1,800,569	$	1,838,567
Less-Accumulated provision for depreciation		709,895		772,123
		1,090,674		1,066,444
Construction work in progress		21,735		21,980
		1,112,409		1,088,424
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		216,951		192,409
Long-term notes receivable from associated companies		10,453		9,892
Other		34,767		34,922
		262,171		237,223
CURRENT ASSETS:
Cash and cash equivalents		120		121
Notes receivable from associated companies		18,769		10,467
Receivables-
Customers (less accumulated provisions of $4,578,000 and $4,943,000 respectively, for uncollectible accounts)		119,858		118,933
Associated companies		118,245		45,934
Other (less accumulated provisions of $68,000 for uncollectible accounts in 2003)		15,493		22,750
Prepayments and other		11,057		6,600
		283,542		204,805
DEFERRED CHARGES:
Regulatory assets		693,133		1,028,432
Goodwill		869,585		884,279
Other		24,438		30,824
		1,587,156		1,943,535
	$	3,245,278	$	3,473,987
CAPITALIZATION AND LIABILITIES
CAPITALIZATION(See Consolidated Statements of Capitalization):
Common stockholder’s equity	$	1,285,419	$	1,292,667
Long-term debt and other long-term obligations		701,736		636,301
		1,987,155		1,928,968
CURRENT LIABILITIES:
Currently payable long-term debt		30,435		40,469
Short-term borrowings (Note 10)-
Associated companies		80,090		65,335
Accounts payable-
Associated companies		88,879		45,459
Other		26,097		33,878
Accrued taxes		11,957		8,762
Accrued interest		11,618		11,848
Other		23,076		22,162
		272,152		227,913
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		305,389		297,140
Accumulated deferred investment tax credits		10,868		11,696
Power purchase contract loss liability		349,980		584,340
Nuclear fuel disposal costs		38,408		37,936
Asset retirement obligation		132,887		210,178
Retirement benefits		82,218		105,552
Other		66,221		70,264
		985,971		1,317,106
COMMITMENTS AND CONTINGENCIES
(Notes 5 and 11)
	$	3,245,278	$	3,473,987

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

15

METROPOLITAN 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 900,000 shares
859,500 shares outstanding	$	1,289,943		$	1,298,130
Accumulated other comprehensive loss (Note 2(F))		(43,490	)		(32,474	)
Retained earnings (Note 8(A))		38,966			27,011
Total common stockholder's equity		1,285,419			1,292,667
LONG-TERM DEBT (Note 8(C)):
First mortgage bonds:
6.340% due 2004		--			40,000
6.770% due 2005		30,000			30,000
6.360% due 2006		--			17,000
6.400% due 2006		--			33,000
6.000% due 2008		7,830			8,265
6.100% due 2021		28,500			28,500
5.950% due 2027		13,690			13,690
Total first mortgage bonds		80,020			170,455
Secured notes:
5.720% due 2006		--			100,000
5.930% due 2007		--			50,000
4.450% due 2010		--			100,000
4.950% due 2013		--			150,000
Total secured notes		--			400,000
Unsecured notes:
5.720% due 2006		100,000			--
5.930% due 2007		50,000			--
4.450% due 2010		100,000			--
4.950% due 2013		150,000			--
4.875% due 2014		250,000			--
7.690% due 2039		--			5,936
7.350% due 2039		--			95,711
Total unsecured notes		650,000			101,647
Net unamortized premium on debt		2,151			4,668
Long-term debt due within one year		(30,435	)		(40,469	)
Total long-term debt		701,736			636,301
TOTAL CAPITALIZATION	$	1,987,155		$	1,928,968

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

16

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

									Accumulated
				Common Stock					Other
	Comprehensive			Number		Carrying			Comprehensive			Retained
	Income			of Shares		Value			Income (Loss)			Earnings
	(Dollars in thousands)
Balance, January 1, 2002					859,500	$	1,274,325		$	11		$	14,617
Net income	$	63,224											63,224
Net unrealized gain on investment		17								17
Net unrealized loss on derivative instruments		(67	)							(67	)
Comprehensive income	$	63,174
Cash dividends on common stock													(60,000	)
Purchase accounting fair value adjustment							23,459
Balance, December 31, 2002					859,500		1,297,784			(39	)		17,841
Net income	$	61,170											61,170
Net unrealized gain on investments		2								2
Net unrealized gain on derivative instruments		78								78
Minimum liability for unfunded retirement    benefits, net of $(23,062,000) of income    taxes		(32,515	)							(32,515	)
Comprehensive income	$	28,735
Cash dividends on common stock													(52,000	)
Purchase accounting fair value adjustment							346
Balance, December 31, 2003					859,500		1,298,130			(32,474	)		27,011
Net income	$	66,955											66,955
Net unrealized loss on investments		(26	)							(26	)
Net unrealized loss on derivative    instruments, net of $(1,279,000) of    income taxes		(1,819	)							(1,819	)
Minimum liability for unfunded retirement    benefits, net of $(6,502,000) of income    taxes		(9,171	)							(9,171	)
Comprehensive income	$	55,939
Cash dividends on common stock													(55,000	)
Purchase accounting fair value adjustment							(8,187	)
Balance, December 31, 2004					859,500		1,289,943			(43,490	)		38,966

CONSOLIDATED STATEMENTS OF PREFERRED STOCK

	Subject to Mandatory Redemption
	Number			Carrying
	of Shares			Value
	(Dollars in thousands)
Balance January 1, 2002		4,000,000		$	92,200
Amortization of fair market value adjustment					209
Balance, December 31, 2002		4,000,000		$	92,409
FIN 46 Deconsolidation
7.35% Series		(4,000,000	)		(92,618)
Amortization of fair market value adjustment					209
Balance, December 31, 2003		--			--
Balance, December 31, 2004		--		$	--

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

17

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

	2004			2003				2002
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	66,955		$	61,170		$		63,224
Adjustments to reconcile net income to net cash from operating activities:
Provision for depreciation		41,161			44,160				50,838
Amortization of regulatory assets		105,675			97,784				97,957
Other amortization		--			--				(2,528	)
Deferred costs recoverable as regulatory assets		(65,981	)		(70,752	)			(86,314	)
Deferred income taxes and investment tax credits, net		18,495			45,832				22,564
Accrued retirement benefits obligations		(186	)		(3,284	)			63
Accrued compensation, net		584			5,531				(2,491	)
Cumulative effect of accounting change (Note 2(G))		--			(371	)			--
Pension trust contribution		(38,823	)		--				--
Decrease (increase) in operating assets:
Receivables		(65,979	)		10,380				(24,672	)
Prepayments and other current assets		(4,457	)		3,131				2,508
Increase (decrease) in operating liabilities:
Accounts payable		35,639			(20,988	)			(18,657	)
Accrued taxes		3,195			(7,334	)			9,059
Accrued interest		(230	)		(4,600	)			(1,020	)
Other		(22,222	)		(28,171	)			(8,657	)
Net cash provided from operating activities		73,826			132,488				101,874
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		247,606			247,696				49,750
Short-term borrowings, net		14,755			--				16,288
Redemptions and Repayments-
Long-term debt		(196,371	)		(260,466	)			(60,000	)
Short-term borrowings, net		--			(22,964	)			--
Dividend Payments-
Common stock		(55,000	)		(52,000	)			(60,000	)
Net cash provided from (used for) financing activities		10,990			(87,734	)			(53,962	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(52,979	)		(43,558	)			(44,533	)
Contributions to decommissioning trusts		(9,483	)		(9,483	)			(12,644	)
Loan payments to associated companies, net		(8,863	)		(7,941	)			--
Other		(13,492	)		664				(324	)
Net cash used for investing activities		(84,817	)		(60,318	)			(57,501	)
Net decrease in cash and cash equivalents		(1	)		(15,564	)			(9,589	)
Cash and cash equivalents at beginning of period		121			15,685				25,274
Cash and cash equivalents at end of period	$	120		$	121		$		15,685
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	43,733		$	51,505		$		46,266
Income taxes (refund)	$	33,693		$	(25,085	)	$		34,385

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

18

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF TAXES

	2004			2003			2002
	(In thousands)
GENERAL TAXES:
State gross receipts *	$	58,900		$	53,462		$	56,043
Real and personal property		1,490			2,510			1,384
Social security and unemployment		3,800			2,448			1
Other		6,267			8,787			9,367
Total general taxes	$	70,457		$	67,207		$	66,795
PROVISION FOR INCOME TAXES:
Currently payable-
Federal	$	12,679		$	(3,435	)	$	15,371
State		7,043			1,763			6,437
		19,722			(1,672	)		21,808
Deferred, net-
Federal		20,599			38,863			19,615
State		(1,276	)		7,791			3,741
		19,323			46,654			23,356
Investment tax credit amortization		(828	)		(822	)		(792	)
Total provision for income taxes	$	38,217		$	44,160		$	44,372
INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income	$	21,968		$	27,367		$	27,447
Other income		16,249			16,639			16,925
Cumulative effect of accounting change		--			154			--
Total provision for income taxes	$	38,217		$	44,160		$	44,372
RECONCILIATION OF FEDERAL INCOME TAX
EXPENSE AT STATUTORY RATE TO TOTAL
PROVISION FOR INCOME TAXES:
Book income before provision for income taxes	$	105,172		$	105,330		$	107,596
Federal income tax expense at statutory rate	$	36,810		$	36,866		$	37,659
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits		(828	)		(822	)		(792	)
Depreciation		2,662			1,736			1,362
State income tax, net of federal benefit		3,749			6,289			6,107
Other, net		(4,176	)		91			36
Total provision for income taxes	$	38,217		$	44,160		$	44,372
ACCUMULATED DEFERRED INCOME TAXES AT
DECEMBER 31:
Property basis differences	$	257,880		$	250,779		$	217,351
Nuclear decommissioning		(4,755	)		(6,405	)		(4,247	)
Deferred sale and leaseback costs		(11,149	)		(10,986	)		(11,366	)
Non-utility generation costs		7,475			2,287			(4,832	)
Purchase accounting basis difference		(642	)		(642	)		(642	)
Sale of generation assets		(1,419	)		(1,419	)		(1,419	)
Regulatory transition charge		95,056			88,020			88,315
Customer receivables for future income taxes		40,636			46,010			50,259
Other comprehensive income		(30,843	)		(23,062	)		--
Employee benefits		(5,289	)		(17,252	)		--
Other		(41,561	)		(30,190	)		(16,662	)
Net deferred income tax liability	$	305,389		$	297,140		$	316,757

* 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.

19

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.   ORGANIZATION AND BASIS OF PRESENTATION:

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

The Company follows GAAP and complies with the regulations, orders, policies and practices prescribed by the SEC, 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. Revenue amounts related to transmission activities previously recorded as wholesale electric sales revenues were reclassified as transmission revenues. Expenses (including transmission and congestion charges) were reclassified among purchased power, other operating costs and amortization of regulatory assets to conform with the current year presentation of generation commodity costs.

The Company consolidates all majority-owned subsidiaries over which the Company exercises control and, when applicable, entities for which the Company has a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. Investments in nonconsolidated affiliates (20-50 percent owned companies, joint ventures and partnerships) over which the Company has the ability to exercise significant influence, but not control, are accounted for on the equity basis.

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

2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

(A)   ACCOUNTING FOR THE EFFECTS OF REGULATION

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

• are established by a third-party regulator with the authority to set rates that bind customers;
• are cost-based; and
• can be charged to and collected from customers.

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

Regulatory Assets-

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

20

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

	2004			2003
	(In millions)
Regulatory transition costs	$	692		$	926
Customer receivables for future income taxes		90			103
Nuclear decommissioning costs		(122	)		(26	)
Employee postretirement benefit costs		16			18
Loss on reacquired debt		17			8
Other		--			(1	)
Total	$	693		$	1,028

Regulatory transition charges as of December 31, 2004 include $0.5 billion for the deferral of above-market costs from power supplied by NUGs. These costs are being recovered through CTC revenues. The regulatory asset for above-market NUG costs and a corresponding liability are adjusted to fair value at the end of each quarter.

Accounting for Generation Operations-

The application of SFAS 71 was discontinued in 1998 with respect to the Company's generation operations. The Company subsequently divested substantially all of its generating assets. The SEC's interpretive guidance and EITF 97-4 regarding asset impairment measurement provides 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. Net assets included in utility plant relating to the operations for which the application of SFAS 71 was discontinued, were $13 million as of December 31, 2004.

(B) CASH AND SHORT-TERM FINANCIAL INSTRUMENTS-

All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value.

(C)    REVENUES AND RECEIVABLES-

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

Receivables from customers include sales to residential, commercial and industrial customers and sales to wholesale customers. There was no material concentration of receivables as of December 31, 2004 or 2003, with respect to any particular segment of the Company's customers. Total customer receivables were $120 million (billed - $74 million and unbilled - $46 million) and $119 million (billed - $70 million and unbilled - $49 million) as of December 31, 2004 and 2003, respectively.

(D) PROPERTY, PLANT AND EQUIPMENT-

As a result of the Company's acquisition by FirstEnergy in 2001, a portion of the Company’s property, plant and equipment was adjusted to reflect fair value. The majority of the Company’s property, plant and equipment continues to be reflected at original cost since such assets remain subject to rate regulation on a historical cost basis. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. The Company's accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred.

The Company provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annualized composite rate was approximately 2.4% in 2004, 2.6% in 2003 and 3.0% in 2002. The decrease in the composite depreciation rate reflects changes in the depreciable plant base due to assets with higher depreciation rates being fully depreciated since 2002.

21

(E) ASSET IMPAIRMENTS-

Long-Lived Assets

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

Goodwill

In a business  combination, the excess of the purchase price over the estimated  fair values of assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, the Company evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If an impairment is indicated, the Company recognizes a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. The Company's 2004 annual review was completed in the third quarter of 2004 with no impairment indicated. The forecasts used in the Company's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on the Company's future evaluations of goodwill. As of December 31, 2004, the Company had $870 million of goodwill. In 2004, the Company adjusted goodwill for interest received on a pre-merger income tax refund and for the reversal of tax valuation allowances related to income tax benefits realized attributable to prior period capital loss carryforwards that were offset by capital gains generated in 2004.

Investments

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

(F) COMPREHENSIVE INCOME-

Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholder’s equity except those resulting from transactions with FirstEnergy. As of December 31, 2004 and December 31, 2003, accumulated other comprehensive loss consisted of a minimum liability for unfunded retirement benefits of $42 million and $33 million, respectively. As of December 31, 2004 accumulated other comprehensive loss also consisted of unrealized losses on derivative instrument hedges of $2 million.

(G) CUMULATIVE EFFECT OF ACCOUNTING CHANGE

As a result of adopting SFAS 143 in January 2003, asset retirement costs were recorded in the amount of $186 million as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $186 million. The ARO liability on the date of adoption was $198 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. The remaining cumulative effect adjustment for unrecognized depreciation and accretion, offset by the reduction in the existing decommissioning liabilities and the reversal of accumulated estimated removal costs for non-regulated generation assets, was a $371,000 increase to income, $217,000 net of tax in the year ended December 31, 2003. If SFAS 143 had been applied during 2002, the impact would not have been material to the Company’s Consolidated Statements of Income.

22

(H) INCOME TAXES-

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

(I) TRANSACTIONS WITH AFFILIATED COMPANIES-

Operating revenues, operating expenses and other income included transactions with affiliated companies, primarily FESC, GPUS and FES. GPUS (until it ceased operations in mid-2003) and FESC have provided legal, accounting, financial and other corporate support services to the Company. The Company also entered into sale and purchase transactions with affiliates (JCP&L and Penelec) during 2002. Effective September 1, 2002, the Company purchases a portion of its PLR responsibility from FES through a wholesale power sale agreement. The primary affiliated companies transactions are as follows:

	2004		2003		2002
	(In millions)
Operating Revenues:
Wholesale sales-affiliated companies	$	--	$	--	$	19
Operating Expenses:
Power purchased from FES		434		277		172
Service Company support services		46		50		68
Power purchased from other affiliates		--		2		10

FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Company from FESC, which is a subsidiary of FirstEnergy and a "mutual service company" as defined in Rule 93 of the PUHCA. The vast 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 a net $33 million receivable from affiliates for OPEB obligations.

3.   PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS:

FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of the Company's 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 (the Company's share was $39 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 (the Company's share was $23 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.

23

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.

24

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

Obligations and Funded Status	Pension Benefits						Other Benefits
As of December 31	2004			2003			2004			2003
	(In millions)
Change in benefit obligation
Benefit obligation as of January 1	$	4,162		$	3,866		$	2,368		$	2,077
Service cost		77			66			36			43
Interest cost		252			253			112			136
Plan participants’ contributions		--			--			14			6
Plan amendments		--			--			(281	)		(123	)
Actuarial (gain) loss		134			222			(211	)		323
Benefits paid		(261	)		(245	)		(108	)		(94	)
Benefit obligation as of December 31	$	4,364		$	4,162		$	1,930		$	2,368
Change in fair value of plan assets
Fair value of plan assets as of January 1	$	3,315		$	2,889		$	537		$	473
Actual return on plan assets		415			671			57			88
Company contribution		500			--			64			68
Plan participants’ contribution		--			--			14			2
Benefits paid		(261	)		(245	)		(108	)		(94	)
Fair value of plan assets as of December 31	$	3,969		$	3,315		$	564		$	537
Funded status	$	(395	)	$	(847	)	$	(1,366	)	$	(1,831	)
Unrecognized net actuarial loss		885			919			730			994
Unrecognized prior service cost (benefit)		63			72			(378	)		(221	)
Unrecognized net transition obligation		--			--			--			83
Net asset (liability) recognized	$	553		$	144		$	(1,014	)	$	(975	)
Amounts Recognized in the Consolidated Balance Sheets As of December 31
Accrued benefit cost	$	(14	)	$	(438	)	$	(1,014	)	$	(975	)
Intangible assets		63			72			--			--
Accumulated other comprehensive loss		504			510			--			--
Net amount recognized	$	553		$	144		$	(1,014	)	$	(975	)
Company's share of net amount recognized	$	49		$	10		$	(59	)	$	(59	)
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	%

25

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

	Pension Benefits									Other Benefits
Components of Net Periodic Benefit Costs	2004			2003			2002			2004			2003			2002
	(In millions)
Service cost	$	77		$	66		$	59		$	36		$	43		$	29
Interest cost		252			253			249			112			137			114
Expected return on plan assets		(286	)		(248	)		(346	)		(44	)		(43	)		(52	)
Amortization of prior service cost		9			9			9			(40	)		(9	)		3
Amortization of transition obligation (asset)		--			--			--			--			9			9
Recognized net actuarial loss		39			62			--			39			40			11
Net periodic cost (income)	$	91		$	142		$	(29	)	$	103		$	177		$	114
Company's share of net periodic cost (income)	$	--		$	5		$	(11	)	$	3		$	7		$	3

Weighted-Average Assumptions Used										Other Benefits
to Determine Net Periodic Benefit Cost	Pension 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:

26

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

Pursuant to FSP 106-1 issued January 12, 2004, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 because of a plan amendment during the quarter, which required remeasurement of the plan's obligations. The plan amendment, which increases cost-sharing by employees and retirees effective January 1, 2005, reduced the Company's postretirement benefit costs by $2 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 FSP106-2. The subsidy reduced the Company's net periodic postretirement benefit costs by $4 million during 2004.

As a result of its voluntary contribution and the increased market value of pension plan assets, the Company reduced its accrued benefit cost as of December 31, 2004 by $23 million. As prescribed by SFAS 87, the Company increased its additional minimum liability by $16 million, offset by a charge to OCI. The balance in AOCL of $42 million (net of $30 million in deferred taxes) will reverse in future periods to the extent the fair value of trust assets exceeds the accumulated benefit obligation.

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

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

4. FAIR VALUE OF FINANCIAL INSTRUMENTS:

Long-term Debt and Other Long-term Obligations-

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

	2004				2003
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Long-term debt	$	730	$	731	$	576	$	593
Subordinated debentures to affiliated trusts		--		--		96		104
	$	730	$	731	$	672	$	697

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 corporations with credit ratings similar to the Company’s ratings.

27

Investments-

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

	2004				2003
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Debt securities:(1)
-Government obligations	$	78	$	78	$	72	$	72
-Corporate debt securities		5		5		6		6
		83		83		78		78
Equity securities(1)		137		137		117		117
	$	220	$	220	$	195	$	195

⁽¹⁾ Includes nuclear decommissioning trust investments.

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 decommissioning trust investments, which are classified as available-for-sale securities. The Company has no securities held for trading purposes. The following table summarizes the amortized cost basis, gross unrealized gains and losses and fair values for decommissioning trust investments as of December 31:

	2004								2003
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
	(In millions)
Debt securities	$	80	$	3	$	--	$	83	$	74	$	4	$	--	$	78
Equity securities		113		24		3		134		75		40		1		114
	$	193	$	27	$	3	$	217	$	149	$	44	$	1	$	192

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	$	179	$	84	$	65
Gross realized gains		30		2		1
Gross realized losses		1		1		1
Interest and dividend income		6		5		5

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

	Less Than 12 Months				12 Months or More				Total
	Fair		Unrealized		Fair		Unrealized		Fair		Unrealized
	Value		Losses		Value		Losses		Value		Losses
(In millions)
Debt securities	$	10	$	--	$	6	$	--	$	16	$	--
Equity securities		21		3		1		--		22		3
	$	31	$	3	$	7	$	--		38	$	3

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

5. LEASES:

Consistent with regulatory treatment, the rentals for capital and operating leases are charged to operating expenses on the Consolidated Statements of Income. The Company’s most significant operating lease relates to the sale and leaseback of a portion of its ownership interest in the Merrill Creek Reservoir project. The interest element related to this lease was $1.6 million, $1.6 million and $0.2 million for the years 2004, 2003 and 2002.

As of December 31, 2004, the future minimum lease payments on the Company’s Merrill Creek operating lease, net of reimbursements from sublessees, are: $1.5 million, $1.5 million, $1.5 million, $1.5 million and $1.9 million for the years 2005 through 2009, respectively, and $41.9 million for the years thereafter. The Company’s Merrill Creek lease payments were offset against the actual net divestiture proceeds received from the 1999 sales of its generating assets.

6. VARIABLE INTEREST ENTITIES:

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

The Company has evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to the Company and the contract price for power is correlated with the plant’s variable costs of production. The Company maintains several long-term power purchase agreements with NUG entities. The agreements were structured pursuant to the Public Utility Regulatory Policies Act of 1978. The Company was not involved in the creation of, and has no equity or debt invested in, these entities.

The Company has determined that for all but one of these entities, the Company has no variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of FIN 46R. The Company may hold a variable interest in the remaining entity, which sells its output at variable price that correlates to some extent with the operating costs of the plant.

As required by FIN 46R, the Company requests on a quarterly basis, the information necessary from this entity to determine whether it is a VIE or whether the Company is the primary beneficiary. The Company has been unable to obtain the requested information, which was deemed by the requested entity to be proprietary. As such, the Company applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R. The maximum exposure to loss from this entity results from increases in the variable pricing component under the contract terms and cannot be determined without the requested data. The purchased power costs from this entity during 2004, 2003 and 2002 were $54 million, $53 million and $53 million, respectively.

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7. REGULATORY MATTERS:

In late 2003 and early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task Force) regarding enhancements to regional reliability. With respect to each of these reliability enhancement initiatives, FirstEnergy submitted its response to the respective entity according to any required response dates. In 2004, FirstEnergy completed implementation of all actions and initiatives related to enhancing area reliability, improving voltage and reactive management, operator readiness and training, and emergency response preparedness recommended for completion in 2004. Furthermore, FirstEnergy certified to NERC on June 30, 2004, with minor exceptions noted, that FirstEnergy had completed the recommended enhancements, policies, procedures and actions it had recommended be completed by June 30, 2004. In addition, FirstEnergy requested, and NERC provided, a technical assistance team of experts to assist in implementing and confirming timely and successful completion of various initiatives. The NERC-assembled independent verification team confirmed on July 14, 2004, that FirstEnergy had implemented the NERC Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts required to be completed by June 30, 2004, as well as NERC recommendations contained in the Control Area Readiness Audit Report required to be completed by summer 2004, and recommendations in the U.S. - Canada Power System Outage Task Force Report directed toward FirstEnergy and required to be completed by June 30, 2004, with minor exceptions noted by FirstEnergy. On December 28, 2004, FirstEnergy submitted a follow-up to its June 30, 2004 Certification and Report of Completion to NERC addressing the minor exceptions, which are now essentially complete.

FirstEnergy is proceeding with the implementation of the recommendations that were to be 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 the Company. The Company 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 the Company'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, the Company filed a settlement agreement with the PPUC that addresses the issues related to this investigation. As part of the settlement, the Company, 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.

In June 2001, the PPUC approved the Settlement Stipulation with all of the major parties in the combined merger and rate relief proceedings which approved the FirstEnergy/GPU merger and provided the Company PLR deferred accounting treatment for energy costs. A February 2002 Commonwealth Court of Pennsylvania decision affirmed the PPUC decision regarding approval of the merger, remanded the issues of quantification and allocation of merger savings to the PPUC and denied the PLR deferral accounting treatment. In October 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC’s June 2001 order in its entirety. In accordance with the PPUC's direction, the Company filed supplements to its tariffs which were effective October 2003 that reflected the CTC rates and shopping credits in effect prior to the June 21, 2001 order.

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In response to its October 8, 2003 petition, the PPUC denied the Company's accounting request regarding the CTC rate/shopping credit swap by requiring the Company to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. The Company subsequently filed with the Commonwealth Court, on October 31, 2003, an Application for Clarification with the judge, a Petition for Review of the PPUC's October 2 and October 16 Orders, and an application for reargument if the judge, in his clarification order, indicates that the Company's Objection was intended to be denied on the merits. The Reargument Brief before the Commonwealth Court was filed January 28, 2005.

In accordance with  PPUC directives, Met-Ed  and Penelec have been  negotiating with interested parties in an attempt to resolve the merger savings issues that are the subject of remand from the Commonwealth Court. These companies' combined portion of total merger savings is estimated to be approximately $31.5 million. If no settlement can be reached, Met-Ed and Penelec will take the position that any portion of such savings should be allocated to customers during each company's next rate proceeding.

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

On January 12, 2005, the Company filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005 estimated to be approximately $4 million per month. Various parties have intervened in this case.

8. CAPITALIZATION:

(A) RETAINED EARNINGS-

In general, the Company’s FMB indentures restrict the payment of dividends or distributions on or with respect to the Company’s common stock to amounts credited to earned surplus since the date of its indenture. As of December 31, 2004, the Company had retained earnings available to pay common stock dividends of $35.6 million, net of amounts restricted under the Company’s FMB indenture.

(B) PREFERRED AND PREFERENCE STOCK-

The Company’s preferred stock authorization consists of 10 million shares without par value. No preferred shares are currently outstanding.

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

Subordinated Debentures to Affiliated Trust

The Company had formed a statutory business trust to sell preferred securities and invest the gross proceeds in subordinated debentures. Ownership of the Company's trust had been through a separate wholly owned limited partnership. In this transaction, the trust had invested the gross proceeds from the sale of its preferred securities in the preferred securities of the limited partnership, which in turn invested those proceeds in the 7.35% subordinated debentures of the Company. In June 2004, the Company extinguished the subordinated debentures held by its affiliated trust and redeemed all of the associated 7.35% preferred securities (aggregate value of $100 million).

Other Long-term Debt

The Company’s FMB indenture, which secures all of the Company’s FMBs, serve as a direct first mortgage lien on substantially all of the Company’s property and franchises, other than specifically excepted property.

The Company has various debt covenants under its financing arrangements. The most restrictive of these relate to the nonpayment of interest and/or principal on debt, which could trigger a default. Cross-default provisions also exist between FirstEnergy and the Company.

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Based on the amount of bonds authenticated by the Trustee through December 31, 2004 the Company’s annual sinking fund requirements for all bonds issued under the mortgage amount to $6 million. The Company expects to fulfill its sinking fund obligation by providing refundable bonds to the Trustee.

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

	(In millions)
2005	$ 30
2006		101
2007		50
2008		7
2009		--

The Company’s obligations to repay certain pollution control revenue bonds are secured by several series of FMBs. Certain pollution control revenue bonds are entitled to the benefit of noncancelable municipal bond insurance policies of $42 million to pay principal of, or interest on, the pollution control revenue bonds.

9. ASSET RETIREMENT OBLIGATION-

In January 2003, the Company implemented SFAS 143, which provides accounting standards for retirement obligations associated with tangible long-lived assets. This statement requires recognition of the fair value of a liability for an ARO in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the 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 Company identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning. The ARO liability as of the date of adoption of SFAS 143 was $198 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, the Company recognized decommissioning liabilities of $260 million. The Company expects substantially all nuclear decommissioning costs to be recoverable through regulated rates. Therefore, a regulatory liability of $61 million was recognized upon adoption of SFAS 143. The ARO includes the Company's obligation for nuclear decommissioning of TMI-2. The Company's share of the obligation to decommission TMI-2 was developed based on a site-specific study performed by an independent engineer. The Company utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO. The Company maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of December 31, 2004, the fair value of the decommissioning trust assets was $217 million.

In the third quarter of 2004, the Company revised the ARO associated with TMI-2 as the result of a recently completed study and the anticipated operating license extension for TMI-1. The abandoned TMI-2 is adjacent to TMI-1 and the units are expected to be decommissioned concurrently. The net decrease in the Company's TMI-2 ARO liability and corresponding regulatory asset was $89 million.

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	$	210		$	198
Accretion		12			12
Revisions in estimated cash flows		(89	)		--
Ending balance as of December 31	$	133		$	210

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The following table provides the year-end balance of the ARO related to nuclear decommissioning 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	$187
Accretion	11
Ending balance as of December 31	$198

10. SHORT-TERM BORROWINGS:

The Company may borrow from its affiliates on a short-term basis. As of December 31, 2004, the Company had total short-term borrowings of $80 million from its affiliates. The weighted average interest rates on short-term borrowings outstanding at December 31, 2004 and 2003 were 2.0% and 1.7%, respectively.

The Company has, through a separate wholly owned subsidiary, a receivables financing agreement under which the Company can borrow up to an aggregate of $80 million at rates based on certain bank commercial paper and is required to pay an annual facility fee of 0.30% on the entire finance limit. This financing agreement expires on March 29, 2005. These receivables financing arrangements are expected to be renewed prior to expiration.

11. COMMITMENTS, GUARANTEES AND CONTINGENCIES:

(A) NUCLEAR INSURANCE-

The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $10.8 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. Based on its present ownership interest in TMI-2, the Company is exempt from any potential assessment under the industry retrospective rating plan.

The Company is also insured as to its interest in TMI-2 under a policy issued to the operating company for the plant. Under this policy, $150 million is provided for property damage and decontamination and decommissioning costs. Under this policy, the Company can be assessed a maximum of approximately $0.4 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses.

The Company intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at TMI-2 exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by the Company’s insurance policies, or to the extent such insurance becomes unavailable in the future, the Company would remain at risk for such costs.

(B) ENVIRONMENTAL MATTERS-

The Company has been named as a PRP at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets, based on estimates of the total costs of cleanup, the Company's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. The Company has accrued liabilities aggregating approximately $26,000 as of December 31, 2004. The Company accrues environmental liabilities only when it concludes that it is probable that an obligation for such costs exists and can reasonably determine the amount of such costs. Unasserted claims are reflected in the Company's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

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(C) OTHER LEGAL PROCEEDINGS-

Power Outages and Related Litigation

On August 14,   2003, various states and parts of  southern  Canada  experienced  widespread power  outages. The outages  affected  approximately 1.4 million customers in FirstEnergy's service area. On April 5, 2004, the U.S. - Canada Power System Outage Task Force released its final report on the outages. In the final report, the Task Force concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contains 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations relate to broad industry or policy matters while one, including subparts, relates to activities the Task Force recommends be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which are consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy certified to NERC on June 30, 2004, completion of various reliability recommendations and further received independent verification of completion status from a NERC verification team on July 14, 2004 with minor exceptions noted by FirstEnergy (see Regulatory Matters above). 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 and the Company have not accrued a liability as of December 31, 2004 for any expenditures in excess of those actually incurred through that date.

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

Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to the Company's normal business operations, pending against the Company, the most significant of which are described above.

12. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS:

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

In December 2004, the FASB issued this Statement  amending APB 29, which was based on the principle that  nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this statement are effective for nonmonetary exchanges occurring in fiscal periods beginning after June 15, 2005 and are to be applied prospectively. The Company is currently evaluating this standard but does not expect it to have a material impact on the financial statements.

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

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

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

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

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

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

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

Issued in December 2004, FSP 109-1 provides guidance related to the provision within the American Jobs Creation Act of 2004 (Act) that provides a tax deduction on qualified production activities. The Act includes a tax deduction of up to 9 percent (when fully phased-in) of the lesser of (a) "qualified production activities income," as defined in the Act, or (b) taxable income (after the deduction for the utilization of any net operating loss carryforwards). This tax deduction is limited to 50 percent of W-2 wages paid by the taxpayer. The FASB believes that the deduction should be accounted for as a special deduction in accordance with SFAS No. 109, "Accounting for Income Taxes." FirstEnergy is currently evaluating this FSP but does not expect it to have a material impact on the Company's financial statements.

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

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

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13.   SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):

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

	March 31,		June 30,		Sept. 30,		Dec. 31,
Three Months Ended	2004		2004		2004		2004
	(In millions)
Operating Revenues	$	260.9	$	242.0	$	285.4	$	282.5
Operating Expenses and Taxes		237.6		228.5		265.1		253.4
Operating Income		23.3		13.5		20.3		29.1
Other Income		5.5		6.2		6.9		7.0
Net Interest Charges		10.8		13.0		10.1		10.9
Net Income	$	18.0	$	6.7	$	17.1	$	25.2

	March 31,		June 30,		Sept. 30,		Dec. 31,
Three Months Ended	2003		2003		2003		2003
	(In millions)
Operating Revenues	$	251.2	$	217.7	$	261.2	$	239.7
Operating Expenses and Taxes		227.2		199.2		242.0		217.5
Operating Income		24.0		18.5		19.2		22.2
Other Income		5.2		5.3		5.2		6.1
Net Interest Charges		12.4		11.0		10.7		10.7
Income Before Cumulative Effect of Accounting Change		16.8		12.8		13.7		17.6
Cumulative Effect of Accounting Change (Net of Income Taxes)		0.2		--		--		--
Net Income	$	17.0	$	12.8	$	13.7	$	17.6

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