JERSEY CENTRAL POWER & LIGHT COMPANY

2004 ANNUAL REPORT TO STOCKHOLDERS

Jersey Central Power & Light Company is a wholly owned electric utility operating subsidiary of FirstEnergy Corp. It engages in the distribution and sale of electric energy in an area of approximately 3,300 square miles in New Jersey. It also engages in the sale, purchase and interchange of electric energy with other electric companies. The area it serves has a population of approximately 2.5 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		4-14
Consolidated Statements of Income		15
Consolidated Balance Sheets		16
Consolidated Statements of Capitalization		17
Consolidated Statements of Common Stockholder's Equity		18
Consolidated Statements of Preferred Stock		18
Consolidated Statements of Cash Flows		19
Consolidated Statements of Taxes		20
Notes to Consolidated Financial Statements		21-36

GLOSSARY OF TERMS

The following abbreviations and acronyms are used in this report to identify Jersey Central Power & Light 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
JCP&L Transition	JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition Bonds
Met-Ed	Metropolitan Edison Company, an affiliated Pennsylvania electric utility
OE	Ohio Edison Company, an affiliated Ohio electric utility
Penelec	Pennsylvania Electric Company, an affiliated Pennsylvania electric utility
Penn	Pennsylvania Power Company, an affiliated Pennsylvania electric utility
TE	The Toledo Edison Company, an affiliated Ohio electric utility
The following abbreviations and acronyms are used to identify frequently used terms in this report:
AOCL	Accumulated Other Comprehensive Loss
APB 29	APB Opinion No. 29, "Accounting for Stock Issued to Employees"
ARO	Asset Retirement Obligation
BGS	Basic Generation Service
CTC	Competitive Transition Charge
ECAR	East Central Area Reliability Coordination Agreement
EITF	Emerging Issues Task Force
EITF 03-1	EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its Application to Certain Investments”
EITF 03-16	EITF Issue No. 03-16, “Accounting for Investments in Limited Liability Companies”
EITF97-4	EITF Issue No. 97-4 “Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statements No. 71 and 101”
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN 46R	FASB Interpretation (revised December 2003), "Consolidation of Variable Interest Entities"
FMB	First Mortgage Bonds
FSP	FASB Staff Position
FSP EITF 03-1-1	FASB Staff Position No. EITF Issue 03-1-1, "Effective Date of Paragraphs 10-20 of EITF Issue No. 03-1, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments"
FSP 106-1	FASB Staff Position No.106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003"
FSP 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
Medicare Act	Medicare Prescription Drug, Improvement and Modernization Act of 2003
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service
MTC	Market Transition Charge
MW	Megawatts
NERC	North American Electric Reliability Council
NJBPU	New Jersey Board of Public Utilities
NUG	Non-Utility Generation
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
PJM	PJM Interconnection L.L.C.

i

GLOSSARY OF TERMS, Cont’d

PRP	Potentially Responsible Party
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act
S&P	Standard & Poor’s Ratings Service
SBC	Societal Benefits Charge
SEC	United States Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
SFAS 71	SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
SFAS 87	SFAS No. 87, "Employers' Accounting for Pensions"
SFAS 101	SFAS No. 101, "Accounting for Discontinuation of Application of SFAS 71"
SFAS 106	SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions"
SFAS 115	SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities"
SFAS 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 140	SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities”
SFAS 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
TBC	Transition Bond Charge
TMI-1	Three Mile Island Unit 1
TMI-2	Three Mile Island Unit 2
VIE	Variable Interest Entity

ii

MANAGEMENT REPORTS

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 firms' 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.

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 Jersey Central

Power & Light Company:

We have completed an integrated audit of Jersey Central Power & Light 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 Jersey Central Power & Light 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 9 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's 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

JERSEY CENTRAL POWER & LIGHT COMPANY

SELECTED FINANCIAL DATA

										Nov. 7 -			Jan. 1 -
	2004			2003			2002			Dec. 31, 2001			Nov. 6, 2001		2000
	(Dollars in thousands)
Operating Revenues	$	2,206,987		$	2,359,646		$	2,328,415		$	282,902		$	1,838,638	$	1,979,297
Operating Income	$	183,909		$	146,775		$	335,209		$	43,666		$	292,847	$	283,227
Net Income	$	111,639		$	68,017		$	251,895		$	30,041		$	34,467	$	210,812
Earnings on Common Stock	$	111,139		$	68,129		$	253,359		$	29,343		$	29,920	$	203,908
Total Assets	$	7,291,184		$	7,579,044		$	8,052,755		$	8,039,998				$	6,009,054
Capitalization as of December 31:
Common Stockholder’s Equity	$	3,155,362		$	3,153,974		$	3,274,069		$	3,163,701				$	1,459,260
Preferred Stock-
Not Subject to Mandatory Redemption		12,649			12,649			12,649			12,649					12,649
Subject to Mandatory Redemption		--			--			--			44,868					51,500
Company-Obligated Mandatorily Redeemable Preferred Securities		--			--			125,244			125,250					125,000
Long-Term Debt		1,238,984			1,095,991			1,210,446			1,224,001					1,093,987
Total Capitalization	$	4,406,995		$	4,262,614		$	4,622,408		$	4,570,469				$	2,742,396
Capitalization Ratios:
Common Stockholder’s Equity		71.6	%		74.0	%		70.8	%		69.2	%				53.2	%
Preferred Stock-
Not Subject to Mandatory Redemption		0.3			0.3			0.3			0.3					0.5
Subject to Mandatory Redemption		--			--			--			1.0					1.9
Company-Obligated Mandatorily Redeemable Preferred Securities		--			--			2.7			2.7					4.5
Long-Term Debt		28.1			25.7			26.2			26.8					39.9
Total Capitalization		100.0	%		100.0	%		100.0	%		100.0	%				100.0	%
Distribution Kilowatt-Hour Deliveries (Millions):
Residential		9,355			9,104			8,976			1,428			7,042		8,087
Commercial		8,877			8,620			8,509			1,330			6,787		7,706
Industrial		3,070			3,046			3,171			474			2,670		3,307
Other		73			89			81			17			66		82
Total		21,375			20,859			20,737			3,249			16,565		19,182
Customers Served:
Residential		941,917			931,227			921,716			909,494					896,629
Commercial		115,861			114,270			112,385			109,985					107,479
Industrial		2,666			2,705			2,759			2,785					2,835
Other		1,320			1,345			1,393			1,484					1,551
Total		1,061,764			1,049,547			1,038,253			1,023,748					1,008,494

3

JERSEY CENTRAL POWER & LIGHT 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 results in 2003 and 2002.

Results of Operations

Earnings on common stock increased to $111 million from $68 million in 2003 principally due to the absence of non-cash charges aggregating $185 million ($109 million after tax) from a 2003 rate case decision disallowing recovery of certain regulatory assets (see Regulatory Matters) and reduced purchased power costs in 2004 which were partially offset by a decline in operating revenues. In 2003, earnings on common stock decreased to $68 million, from $253 million in 2002, as a result of the disallowed costs from the 2003 rate case decision. In addition, higher operating revenues were more than offset by increases in purchased power and other operating costs causing a decline in earnings.

Operating revenues decreased $153 million or 6.5% in 2004 compared with 2003. The decrease in revenues was due to a $107 million decline in distribution throughput revenues and a $49 million decline in wholesale revenues partially offset by a $11 million increase in retail generation revenues. Our BGS obligation has been transferred to external parties as a result of an NJBPU auction process that extended the termination of our BGS obligation through July 2005 (see Note 7 - Regulatory Matters). We had entered into long-term power purchase agreements in connection with the divestiture of our generation facilities and had sold any power in excess of our retail customer needs to the wholesale market. The long-term purchase agreements ended after the first quarter of 2003 and as a result, sales to the wholesale market subsequently decreased. Retail generation sales revenues increased by $11 million in 2004 compared to 2003 due to higher unit prices resulting from the BGS auction. This increase more than offset a composite 13.2% decrease in kilowatt-hour sales (commercial - 16.0% and industrial - 63.4%), which reflected increases in electric generation services to commercial and industrial customers provided by alternative suppliers. The shopping percentage in our franchise area increased 16.7 percentage points and 46.0 percentage points, for the commercial and industrial sectors respectively, while the percentage of shopping by residential customers was relatively unchanged.

The $107 million decrease in distribution deliveries was due to lower unit prices that more than offset the impact of the 2.5% volume increase in 2004 from the previous year. The lower prices reflected the impact of the distribution rate decrease effective August 1, 2003. Warmer temperatures in the summer and improving economic conditions resulted, in large part, in higher residential, commercial and industrial demand.

Operating revenues increased $31 million in 2003 compared with 2002 due to an $87 million increase in wholesale revenues offset by lower revenues from our distribution deliveries. The wholesale revenues increase in 2003 reflected the impact of the BGS auction discussed above.

4

Distribution deliveries increased slightly in 2003 from the previous year. Lower unit prices in 2003 more than offset the impact of the increased volume and reduced revenues by $64 million. In addition, lower 2003 revenues reflected the impact of the distribution rate decrease effective August 1, 2003. Colder temperatures early in the year resulted in higher residential and commercial demand, which was partially offset by a decrease in industrial demand.

Generation sales revenues in 2003 compared to 2002 were lower by $24 million due to an 8.7% decrease in kilowatt-hour sales. The decrease reflected a 9.1 percentage point increase in customers choosing an alternate supplier in 2003 compared to 2002. The reverse was true in 2002 where some customers who were receiving their power from alternate suppliers returned to us as full service customers.

Changes in kilowatt-hour sales by customer class in 2004 and 2003 are summarized in the following table:

Changes in Kilowatt-hour Sales	2004			2003
Increase (Decrease)
Electric Generation:
Retail		(13.2	)%		(8.7	)%
Wholesale		(19.1	)%		23.1	%
Total Electric Generation Sales		(14.7	)%		(2.4	)%
Distribution Deliveries:
Residential		2.8	%		1.4	%
Commercial		3.0	%		1.3	%
Industrial		0.8	%		(3.9	)%
Total Distribution Deliveries		2.5	%		0.6	%

Operating Expenses and Taxes

Total operating expenses and taxes decreased $190 million in 2004, after increasing $220 million in 2003, compared to the prior year. These increases include the non-cash charges in 2003 for amounts disallowed by the NJBPU in its rate case decision (see Regulatory Matters), of which $153 million was charged to purchased power and $33 million was charged to amortization of regulatory assets. The following table presents changes in 2004 and 2003 from the prior year by expense category.

Operating Expenses and Taxes - Changes	2004			2003
Increase (Decrease)	(In millions)
Fuel and purchased power costs	$	(220	)	$	234
Other operating costs		(18	)		68
Provision for depreciation		(24	)		(23	)
Amortization of regulatory assets		15			73
General taxes		9			(2	)
Income taxes		48			(130	)
Total operating expenses and taxes	$	(190	)	$	220

Excluding the disallowed deferred energy costs of $153 million in 2003, fuel and purchased power decreased $67 million in 2004 compared to 2003. The lower purchased power costs reflected lower kilowatt-hour purchases due to reduced generation sales requirements as discussed above. Other operating expenses decreased $18 million in 2004 compared to 2003, due to cost containment efforts as demonstrated by the 7% decline in the number of employees and the absence in 2004 of storm restoration costs incurred in the third quarter of 2003.

Depreciation expense declined $24 million in 2004 and $23 million in 2003 compared to the preceding year due to reduced depreciation rates effective August 1, 2003 in connection with the NJBPU rate case decision (see Regulatory Matters). Amortization of regulatory assets, excluding $33 million of disallowed costs in 2003 from the rate decision discussed above, increased $48 million in 2004 and $40 in 2003 due to increased regulatory asset recovery in connection with the NJBPU rate case decision.

5

In 2003, excluding the disallowed  deferred energy costs of $153 million, fuel and purchased  power costs increased $81 million, compared to 2002. The increase was due primarily to more power being purchased through two-party agreements and changes to the deferred energy and capacity costs. Other operating expenses increased $68 million in 2003 compared to 2002, due to higher employee benefit costs, storm restoration expenses and costs associated with an accelerated reliability plan within our service territory.

Net Interest Charges

Net interest charges decreased $6 million in 2004 and $5 million in 2003, compared to the previous year, reflecting debt redemptions of $290 million and $252 million, respectively. Those decreases were partially offset by interest on $300 million of senior notes issued in April 2004 and $150 million of senior notes issued in May 2003 which were used to redeem outstanding securities in the second and third quarters of 2003.

Preferred Stock Dividend Requirements

Preferred stock dividend requirements were unchanged in 2004 and decreased $1.4 million in 2003, compared to the prior year, due to the redemptions of cumulative preferred stock pursuant to mandatory and optional sinking fund provisions. We realized non-cash gains of $0.6 million in 2003 on the reacquisition of preferred stock.

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 cash from operations.

Changes in Cash Position

As of December 31, 2004, we had $0.2 million of cash and cash equivalents compared with $0.3 million as of December 31, 2003. The major sources for changes in these balances are summarized below.

Cash Flows From Operating Activities

Our net cash provided from operating activities was $263 million in 2004, $180 million in 2003 and $302 million in 2002, summarized as follows:

Operating Cash Flows	2004			2003			2002
	(In millions)
Cash earnings (1)	$	230		$	325		$	281
Pension trust contribution		(37	)		--			--
Working capital and other		70			(145	)		21
Total	$	263		$	180		$	302

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

⁽²⁾      Pension trust contribution net of $25 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)	$	112		$	68		$	252
Non-Cash Charges (Credits):
Provision for depreciation		75			99			121
Amortization of regulatory assets		279			263			190
Revenue credits to customers		--			(72	)		(43	)
Disallowed regulatory assets		--			153			--
Deferred costs recoverable as regulatory assets		(263	)		(276	)		(352	)
Deferred income taxes		30			62			112
Other non-cash expenses		(3	)		28			1
Cash earnings (Non-GAAP)	$	230		$	325		$	281

6

Net  cash  provided  from  operating  activities  increased  by $83 million in 2004 and decreased by $121 million in 2003, as compared to the previous  year.  The increase in 2004 was due to a $215 million increase in working capital which was partially offset by a $95 million decrease in cash earnings as described under “Results of Operations” and a $37 million after-tax voluntary pension trust contribution. The increase in working capital and other was attributable to a $151 million increase in payables and a $53 million increase associated with a NUG power contract restructuring. The decrease in 2003 was due to a $166 million increase in working capital and other requirements (primarily from a $170 million reduction in payables) which was partially offset by a $44 million increase in cash earnings.

Cash Flows From Financing Activities

Net cash used for financing activities was $82 million, $139 million and $140 million in 2004, 2003 and 2002, respectively. These amounts reflect redemptions of debt and preferred stock, in addition to payments of $90 million in 2004, $138 million in 2003 and $191 million in 2002 for common stock dividends to FirstEnergy. The following table provides details regarding new issues and redemptions during each year:

Securities Issued or Redeemed in	2004		2003		2002
	(In millions)
New Issues
Secured Notes	$	300	$	150	$	--
Transition Bonds (See Note 8(C))		--		--		320
Redemptions
First Mortgage Bonds	$	290	$	150	$	192
Medium Term Notes		--		102		--
Preferred Stock		--		125		52
Transition Bonds		16		--		--
Other		3		--		4
Total Redemptions	$	309	$	377	$	248
Short-term Borrowings, net	$	18	$	231	$	(18	)

We had $249 million of short-term  indebtedness at the end of 2004, compared to $231 million of short-term  debt at the end of 2003. The Company has obtained authorization from the SEC to incur short-term debt up to its charter limit of $415 million (including the utility money pool). We will not issue FMB other than as collateral for senior notes, since our senior note indentures prohibit (subject to certain exceptions) us from issuing any debt which is senior to the senior notes. As of December 31, 2004, we had the capability to issue $644 million of additional senior notes based upon FMB collateral. At year-end 2004, based upon applicable earnings coverage tests and our charter, we could issue $583 million of preferred stock (assuming no additional debt was issued).

We have the ability to borrow from our regulated affiliates and FirstEnergy to meet our short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings 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 the securities of FirstEnergy. The following table shows securities ratings as of December 31, 2004. The ratings outlook on all securities is stable.

Ratings of Securities
	Securities	S&P	Moody’s	Fitch
FirstEnergy	Senior unsecured	BB+	Baa3	BBB-
JCP&L	Senior secured	BBB+	Baa1	BBB+
	Preferred stock	BB	Ba1	BBB

7

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 in investing activities increased $136 million in 2004 and decreased $143 million in 2003. The increase in 2004 resulted primarily from a $56 million increase in property additions and a $79 million decrease in loan repayments from associated companies. The 2003 change was principally due to a $155 million increase in loan repayments from associated companies.

Our capital spending for the period 2005-2007 is expected to be approximately $511 million for property additions and improvements, of which approximately $178 million applies to 2005.

Contractual Obligations

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

Contractual Obligations	Total		2005		2006- 2007		2008- 2009		Thereafter
	(In millions)
Long-term debt (2)	$	1,264	$	17	$	226	$	44	$	977
Short-term borrowings		249		249		--		--		--
Operating leases		62		2		3		4		53
Purchases (1)		3,374		568		1,068		837		901
Total	$	4,949	$	836	$	1,297	$	885	$	1,931

⁽¹⁾  Power purchases under contracts with fixed or minimum quantities and approximate timing.

⁽²⁾  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 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.

Commodity Price Risk

We are exposed to market risk primarily due to fluctuations in electricity and natural gas prices. To manage the volatility relating to these exposures, we use a variety of non-derivative and derivative instruments, including forward contracts, options and futures contracts. The derivatives are used for hedging 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:

8

Increase (Decrease) in the Fair Value of Commodity Derivative Contracts

	Non-Hedge			Hedge		Total
	(In millions)
Change in the Fair Value of Commodity Derivative Contracts
Outstanding net asset as of January 1, 2004	$	16		$	--	$	16
New contract value when entered		--			--		--
Additions/Change in value of existing contracts		(1	)		--		(1	)
Change in techniques/assumptions		--			--		--
Settled contracts		--			--		--
Net Assets - Derivatives Contracts as of December 31, 2004 (1)	$	15		$	--	$	15
Income Statement Impact of Changes in Commodity Derivative Contracts (2)		(1	)	$	--	$	(1	)

⁽¹⁾ Includes $15 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 included on the Consolidated Balance Sheet as of December 31, 2004:

	Non-Hedge		Hedge		Total
			(In millions)
Non-Current--
Other Deferred Charges	$	15	$	--	$	15
Net assets	$	15	$	--	$	15

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 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)	$	4	$	3	$	--	$	--	$	--	$	7
Prices based on models		--		--		2		2		4		8
Total (2)	$	4	$	3	$	2	$	2	$	4	$	15

⁽¹⁾ Broker quote sheets.

⁽²⁾ Includes $15 million from an embedded option that is offset by a regulatory liability and does not affect earnings.

We perform sensitivity analyses to estimate our exposure to the market risk of our commodity position. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on our consolidated financial position or cash flows as of December 31, 2004.

Interest Rate Risk

Our exposure to fluctuations in market interest rates is reduced since our debt has fixed interest rates, as noted in the following table.

9

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																$	218		$	218		$	218
Average interest rate																	4.6	%		4.6	%
Liabilities
Long-term Debt and Other Long-Term Obligations:
Fixed rate	$	17		$	208		$	18		$	19		$	25		$	977		$	1,264		$	1,252
Average interest rate		4.2	%		6.3	%		4.2	%		5.4	%		5.7	%		6.1	%		6.1	%
Short-term Borrowings		249																	$	249		$	249
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 $80 million and $69 million at December 31, 2004 and 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $8 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. To support customer choice, rates were restructured into unbundled service charges and additional non-bypassable charges to recover stranded costs.

Regulatory assets are costs which have been authorized by the NJBPU and the FERC for recovery from customers in future periods 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 of our regulatory assets are expected to continue to be recovered under the provisions of the regulatory proceedings discussed below. Our regulatory assets totaled $2.2 billion and $2.6 billion as of December 31, 2004 and December 31, 2003, respectively.

Regulatory Matters

In July 2003, the NJBPU announced our base electric rate proceeding decision, which reduced our annual revenues effective August 1, 2003 and disallowed $153 million of deferred energy costs. The NJBPU decision also provided for an interim return on equity of 9.5% on our rate base. The decision ordered that a Phase II proceeding be conducted to review whether we are in compliance with current service reliability and quality standards. The NJBPU also ordered that any expenditures and projects undertaken by us to increase our system's reliability reviewed as part of the Phase II proceeding, to determine their prudence and reasonableness for rate recovery. In that Phase II proceeding, the NJBPU could increase our return on equity to 9.75% or decrease it to 9.25%, depending on its assessment of the reliability of our service. Any reduction would be retroactive to August 1, 2003. We recorded charges to net income for the year ended December 31, 2003, aggregating $185 million ($109 million net of tax) consisting of the $153 million of disallowed deferred energy costs and $32 million of other disallowed regulatory assets. In its final decision and order issued on May 17, 2004, the NJPBU clarified the method for calculating interest attributable to the cost disallowances, resulting in a $5.4 million reduction from the amount estimated in 2003. We filed an August 15, 2003 interim motion for rehearing and reconsideration with the NJBPU and a June 1, 2004 supplemental and amended motion for rehearing and reconsideration. On July 7, 2004, the NJBPU granted limited reconsideration and rehearing on the following issues: (1) deferred cost disallowances (2) the capital structure including the rate of return (3) merger savings, including amortization of costs to achieve merger savings; and (4) decommissioning. Management is unable to predict when a decision may be reached by the NJBPU.

10

On July 16, 2004, we filed the Phase II petition and testimony with the NJBPU requesting an increase in base rates of $36 million for the recovery of system reliability costs and a 9.75% return on equity. The filing also requests an increase to the MTC deferred balance recovery of approximately $20 million annually. The Ratepayer Advocate filed testimony on November 16, 2004 and JCP&L submitted rebuttal testimony on January 4, 2005. Settlement conferences are ongoing.

On July 5, 2003, JCP&L experienced a series of 34.5 kilovolt sub-transmission line faults that resulted in outages on the New Jersey Shore. As a result of an investigation into these outages, the NJBPU issued an order to JCP&L on July 23, 2004 to implement actions to improve reliability in accordance with the findings of a Special Reliability Master (SRM) report and an operations audit.

Employee Matters

On December 8, 2004, employees represented by IBEW System Council U-3 began a strike against the Company. The Company continues to utilize management, other non-union personnel from around FirstEnergy’s system and contractors to perform service reliability and priority maintenance work while the union members are on strike. The labor agreement between the Company and System Council U-3 originally expired on October 31, 2003 but was extended several times and ultimately expired on December 7, 2004. The Company and the leadership of System Council U-3 continue to negotiate in an attempt to reach a new agreement and end the work stoppage. It is unknown when such an agreement will be reached or when the work stoppage will end.

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 $47 million as of December 31, 2004, which are being recovered through a non-bypassable SBC. We do not believe environmental remediation costs will have a material adverse effect on our financial condition, cash flows or results of operations.

Power Outages and Related Litigation

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

In August 2002, the trial court granted partial summary judgment to us and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted our motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Court issued a decision on July 8, 2004, affirming the decertification of the originally certified class but remanding for certification of a class limited to those customers directly impacted by the outages of transformers in Red Bank, New Jersey. On September 8, 2004, the New Jersey Supreme Court denied the motions filed by plaintiffs and us for leave to appeal the decision of the Appellate Court. We are unable to predict the outcome of these matters and no liability has been accrued as of December 31, 2004.

11

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 diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contains 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations relate to broad industry or policy matters while one, including subparts, relates to activities the Task Force recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. 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. FirstEnergy’s implementation of these recommendations included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these initiatives already were in process, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its operations or financial results. FirstEnergy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. FirstEnergy has not accrued a liability as of December 31, 2004 for any expenditures in excess of those actually incurred through that date.

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.

Regulatory Accounting

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

Revenue Recognition

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

12

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 our 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 $62 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 $46 million. As prescribed by SFAS 87, we increased our additional minimum liability by $9 million, offset by a charge to OCI. The balance in AOCL of $53 million (net of $37 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 our health care plans, and projections of future medical trend rates.

Long-Lived Assets

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

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

13

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.

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 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 we recognize a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. Our annual review was completed in the third quarter of 2004 with no impairment indicated. The forecasts used in our evaluations 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.

14

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF INCOME

	2004			2003			2002
	(In thousands)
OPERATING REVENUES (Note 2(H))	$	2,206,987		$	2,359,646		$	2,328,415
OPERATING EXPENSES AND TAXES:
Fuel and purchased power (Note 2(H))		1,166,430			1,386,899			1,153,415
Other operating costs (Note 2(H))		350,709			368,714			300,602
Provision for depreciation		75,163			98,711			121,444
Amortization of regulatory assets		278,559			263,227			190,200
General taxes		62,792			53,481			56,049
Income taxes		89,425			41,839			171,496
Total operating expenses and taxes		2,023,078			2,212,871			1,993,206
OPERATING INCOME		183,909			146,775			335,209
OTHER INCOME		7,761			7,026			7,653
NET INTEREST CHARGES:
Interest on long-term debt		80,840			87,681			92,314
Allowance for borrowed funds used during
construction		(615	)		(296	)		(583	)
Deferred interest		(3,545	)		(8,639	)		(8,815	)
Other interest expense		3,351			1,691			(2,643	)
Subsidiary’s preferred stock dividend requirements		--			5,347			10,694
Net interest charges		80,031			85,784			90,967
NET INCOME		111,639			68,017			251,895
PREFERRED STOCK DIVIDEND REQUIREMENTS		500			500			2,125
GAIN ON PREFERRED STOCK REACQUISITION		--			(612	)		(3,589	)
EARNINGS ON COMMON STOCK	$	111,139		$	68,129		$	253,359

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

15

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED BALANCE SHEETS

As of December 31,	2004		2003
	(In thousands)
ASSETS
UTILITY PLANT:
In service	$	3,730,767	$	3,642,467
Less-Accumulated provision for depreciation		1,380,775		1,367,042
		2,349,992		2,275,425
Construction work in progress		75,012		48,985
		2,425,004		2,324,410
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		138,205		125,945
Nuclear fuel disposal trust		159,696		155,774
Long-term notes receivable from associated companies		20,436		19,579
Other		19,379		18,744
		337,716		320,042
CURRENT ASSETS:
Cash and cash equivalents		162		271
Receivables-
Customers (less accumulated provisions of $3,881,000 and $4,296,000
respectively, for uncollectible accounts)		201,415		198,061
Associated companies		86,531		70,012
Other (less accumulated provisions of $162,000 and $1,183,000 respectively)		39,898		46,411
Materials and supplies, at average cost		2,435		2,480
Prepayments and other		31,489		49,360
		361,930		366,595
DEFERRED CHARGES:
Regulatory assets		2,176,520		2,558,214
Goodwill		1,985,036		2,001,302
Other		4,978		8,481
		4,166,534		4,567,997
	$	7,291,184	$	7,579,044
CAPITALIZATION AND LIABILITIES
CAPITALIZATION(See Consolidated Statements of Capitalization):
Common stockholder’s equity	$	3,155,362	$	3,153,974
Preferred stock not subject to mandatory redemption		12,649		12,649
Long-term debt		1,238,984		1,095,991
		4,406,995		4,262,614
CURRENT LIABILITIES:
Currently payable long-term debt		16,866		175,921
Notes payable (Note 10)-
Associated companies		248,532		230,985
Accounts payable-
Associated companies		20,605		42,410
Other		124,733		105,815
Accrued taxes		2,626		919
Accrued interest		10,359		14,843
Other		65,130		58,094
		488,851		628,987
NONCURRENT LIABILITIES:
Power purchase contract loss liability		1,268,478		1,473,070
Accumulated deferred income taxes		645,741		640,208
Nuclear fuel disposal costs		169,884		167,936
Asset retirement obligation		72,655		109,851
Retirement benefits		103,036		159,219
Other		135,544		137,159
		2,395,338		2,687,443
COMMITMENTS AND CONTINGENCIES
(Notes 5 and 11).
	$	7,291,184	$	7,579,044

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

16

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

As of December 31,	2004			2003
(Dollars in thousands, except per share amounts)
COMMON STOCKHOLDER'S EQUITY:
Common stock, par value $10 per share, authorized 16,000,000 shares
15,371,270 shares outstanding	$	153,713		$	153,713
Other paid-in capital		3,013,912			3,029,894
Accumulated other comprehensive loss (Note 2(F))		(55,534	)		(51,765	)
Retained earnings (Note 8(A))		43,271			22,132
Total common stockholder's equity		3,155,362			3,153,974

	Number of Shares Outstanding				Optional Redemption Price
	2004		2003		Per Share		Aggregate
PREFERRED STOCK NOT SUBJECT TO
MANDATORY REDEMPTION (Note 8(B)):
Cumulative, without par value-
Authorized 125,000 shares
4.00% Series		125,000		125,000	$	106.50	$	13,313		12,649			12,649
LONG-TERM DEBT (Note 8(C)):
First mortgage bonds:
7.125% due 2004										--			160,000
6.780% due 2005										--			50,000
6.850% due 2006										40,000			40,000
7.125% due 2009										5,985			6,300
7.100% due 2015										12,200			12,200
8.320% due 2022										--			40,000
7.980% due 2023										--			40,000
7.500% due 2023										125,000			125,000
8.450% due 2025										50,000			50,000
6.750% due 2025										150,000			150,000
Total first mortgage bonds										383,185			673,500
Secured notes:
6.450% due 2006										150,000			150,000
4.190% due 2007										51,723			67,312
5.390% due 2010										52,297			52,297
5.810% due 2013										77,075			77,075
5.625% due 2016										300,000			--
6.160% due 2017										99,517			99,517
4.800% due 2018										150,000			150,000
Total secured notes										880,612			596,201
Unsecured notes:
7.69% due 2039										--			2,968
Net unamortized discount on debt										(7,947	)		(757	)
Long-term debt due within one year										(16,866	)		(175,921	)
Total long-term debt										1,238,984			1,095,991
TOTAL CAPITALIZATION									$	4,406,995		$	4,262,614

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

17

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

												Accumulated
				Common Stock					Other			Other
	Comprehensive			Number		Par			Paid-In			Comprehensive				Retained
	Income			of Shares		Value			Capital			Income (Loss)				Earnings
	(Dollars in thousands)
Balance, January 1, 2002					15,371,270	$	153,713	$		2,981,117		$	(472	)	$		29,343
Net income	$	251,895															251,895
Net unrealized loss on derivative instruments		(393	)										(393	)
Comprehensive income	$	251,502
Cash dividends on preferred stock																	1,465
Cash dividends on common stock																	(190,700	)
Purchase accounting fair value adjustment										48,101
Balance, December 31, 2002					15,371,270		153,713			3,029,218			(865	)			92,003
Net income	$	68,017															68,017
Net unrealized loss on derivative instruments		(3,020	)										(3,020	)
Minimum liability for unfunded retirement benefits, net of $(32,998,000) of income taxes
	(47,880	)										(47,880	)
Comprehensive income	$	17,117
Cash dividends on preferred stock																	(500	)
Cash dividends on common stock																	(138,000	)
Gain on preferred stock reacquisition																	612
Purchase accounting fair value adjustment										676
Balance, December 31, 2003					15,371,270		153,713			3,029,894			(51,765	)			22,132
Net income	$	111,639															111,639
Net unrealized loss on investments		(5	)										(5	)
Net unrealized gain on derivative instruments, net of $1,583,000 of income taxes		1,697											1,697
Minimum liability for unfunded retirement benefits, net of $(3,772,000) of income taxes
	(5,461	)										(5,461	)
Comprehensive income	$	107,870
Cash dividends on preferred stock																	(500	)
Cash dividends on common stock																	(90,000	)
Purchase accounting fair value adjustment										(15,982	)
Balance, December 31, 2004					15,371,270	$	153,713	$		3,013,912		$	(55,534	)	$		43,271

CONSOLIDATED STATEMENTS OF PREFERRED STOCK

	Not Subject to				Subject to
	Mandatory Redemption				Mandatory Redemption
	Number		Carrying		Number			Carrying
	of Shares		Value		of Shares			Value
	(Dollars in thousands)
Balance, January 1, 2002		125,000	$	12,649		5,515,001		$	180,951
Redemptions-
7.52% Series						(265,000	)		(28,951	)
8.65% Series						(250,001	)		(26,750	)
Amortization of fair market
Value adjustment									(6	)
Balance, December 31, 2002		125,000		12,649		5,000,000		$	125,244
Redemptions-
8.56% Series						(5,000,000	)		(125,242	)
Amortization of fair market
value adjustment									(2	)
Balance, December 31, 2003		125,000		12,649		--			--
Balance, December 31, 2004		125,000	$	12,649		--		$	--

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

18

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

	2004			2003			2002
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	111,639		$	68,017		$	251,895
Adjustments to reconcile net income to net
cash from operating activities:
Provision for depreciation		75,163			98,711			121,444
Amortization of regulatory assets		278,559			263,227			190,200
Deferred costs, net		(263,257	)		(276,214	)		(351,950	)
Deferred income taxes and investment tax credits, net		54,887			62,372			112,315
NUG power contract restructuring		52,800			--			--
Pension trust contribution		(62,499	)		--			--
Revenue credits to customers		--			(71,984	)		(43,016	)
Disallowed regulatory assets		--			152,500			--
Accrued retirement benefit obligation		(2,986	)		8,381			--
Accrued compensation, net		1,014			19,864			(59	)
Receivables		(13,360	)		4,528			(14,542	)
Materials and supplies		45			(1,139	)		7
Accounts payable		(2,887	)		(153,953	)		16,399
Other		33,535			5,642			19,597
Net cash provided from operating activities		262,653			179,952			302,290
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		300,000			150,000			318,106
Short-term borrowings, net		17,547			230,985			--
Redemptions and Repayments-
Preferred stock		--			(125,244	)		(51,500	)
Long-term debt		(308,872	)		(251,815	)		(196,033	)
Short-term borrowings, net		--			--			(18,149	)
Dividend Payments-
Common stock		(90,000	)		(138,000	)		(190,700	)
Preferred stock		(500	)		(5,235	)		(2,125	)
Net cash used for financing activities		(81,825	)		(139,309	)		(140,401	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(178,877	)		(122,930	)		(97,346	)
Contributions to decommissioning trusts		(2,895	)		(2,630	)		--
Loan repayments from (payments to) associated companies, net		(857	)		78,112			(77,358	)
Other		1,692			2,253			(13,786	)
Net cash used for investing activities		(180,937	)		(45,195	)		(188,490	)
Net increase (decrease) in cash and cash equivalents		(109	)		(4,552	)		(26,601	)
Cash and cash equivalents at beginning of period		271			4,823			31,424
Cash and cash equivalents at end of period	$	162		$	271		$	4,823
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	83,341		$	101,432		$	92,152
Income taxes	$	58,549		$	16,883		$	83,776

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

19

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF TAXES

	2004			2003			2002
	(In thousands)
GENERAL TAXES:
New Jersey Transitional Energy Facilities Assessment*	$	49,455		$	38,668		$	39,387
Real and personal property		4,894			3,889			4,362
Social security and unemployment		8,287			4,826			--
Other		156			6,098			12,300
Total general taxes	$	62,792		$	53,481		$	56,049
PROVISION FOR INCOME TAXES:
Currently payable (receivable)-
Federal	$	29,862		$	(15,687	)	$	55,731
State		10,363			(245	)		13,809
		40,225			(15,932	)		69,540
Deferred, net-
Federal		50,817			54,252			88,758
State		5,657			10,348			27,108
		56,474			64,600			115,866
Investment tax credit amortization		(1,587	)		(2,228	)		(3,551	)
Total provision for income taxes	$	95,112		$	46,440		$	181,855
INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income	$	89,425		$	41,839		$	171,496
Other income		5,687			4,601			10,359
Total provision for income taxes	$	95,112		$	46,440		$	181,855
RECONCILIATION OF FEDERAL INCOME TAX
EXPENSE AT STATUTORY RATE TO TOTAL
PROVISION FOR INCOME TAXES:
Book income before provision for income taxes	$	206,751		$	114,457		$	433,749
Federal income tax expense at statutory rate	$	72,363		$	40,060		$	151,812
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits		(1,587	)		(2,228	)		(3,551	)
Depreciation		4,485			3,315			7,154
State income tax, net of federal benefit		10,413			7,178			27,111
Other, net		9,438			(1,885	)		(671	)
Total provision for income taxes	$	95,112		$	46,440		$	181,855
ACCUMULATED DEFERRED INCOME TAXES AT
DECEMBER 31:
Property basis differences	$	386,071		$	371,811		$	297,983
Nuclear decommissioning		27,123			34,663			44,775
Deferred sale and leaseback costs		(17,836	)		(16,651	)		(16,451	)
Purchase accounting basis difference		(1,253	)		(1,253	)		(1,253	)
Sale of generation assets		(15,614	)		(17,861	)		(17,861	)
Regulatory transition charge		213,665			197,729			224,117
Provision for rate refund		--			--			(29,370	)
Customer receivables for future income taxes		(27,239	)		(4,519	)		(5,336	)
Oyster Creek securitization		184,245			193,558			202,448
Other comprehensive income		(38,353	)		(32,998	)		--
Employee benefits		1,652			(29,129	)		--
Other		(66,720	)		(55,142	)		(7,331	)
Net deferred income tax liability	$	645,741		$	640,208		$	691,721

* 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.

20

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.   ORGANIZATION AND BASIS OF PRESENTATION:

The consolidated  financial  statements include JCP&L (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, Met-Ed and Penelec.

The Company follows GAAP and complies with the regulations, orders, policies and practices prescribed by the SEC, NJBPU 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. 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 and VIEs for which the Company or any of its subsidiaries is the primary beneficiary. 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.

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 results in 2003 and 2002.

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 NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered from customers under the 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.

21

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

	2004			2003
	(In millions)
Regulatory transition charge	$	2,215		$	2,457
Societal benefits charge		51			82
Property losses and unrecovered plant costs		50			70
Liabilities to customers - income taxes		(58	)		--
Employee postretirement benefit costs		27			30
Loss on reacquired debt		18			15
Spent fuel disposal costs		(1	)		3
Component removal costs		(150	)		(150	)
Other		25			51
Total	$	2,177		$	2,558

Regulatory transition charges as of December 31, 2004 include $1.2 billion for the deferral of above-market costs from power supplied by NUGs. These costs are being recovered through BGS and MTC revenues.

Accounting for Generation Operations-

The application of SFAS 71 was discontinued in 1999 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 operations for which the application of SFAS 71 was discontinued were $39 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 New Jersey. 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 $201 million (billed - $122 million and unbilled - $79 million) and $198 million (billed - $119 million and unbilled - $79 million) as of December 31, 2004 and 2003, respectively.

(D)   PROPERTY, PLANT AND EQUIPMENT-

As a result of the Company's acquisition by FirstEnergy, 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 is reflected at original cost since such assets remain subject to rate regulation on a historical cost basis. In addition to its wholly owned facilities, the Company holds a 50% ownership interest in Yards Creek Pumped Storage Facility, and its net book value was approximately $19.2 million as of December 31, 2004. 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.

22

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 2.1% in 2004, 2.8% in 2003, and 3.5% in 2002. The reduced depreciation rates in 2004 and 2003 reflect reductions from the NJBPU August 2003 rate decision.

(E)   ASSET IMPAIRMENTS-

Long-Lived Assets

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

Goodwill

In a business combination, the excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, the Company evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If an impairment is indicated, the Company recognizes a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. The Company's 2004 annual review was completed in the third quarter of 2004 with no impairment indicated. The forecasts used in the Company's evaluation of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on the Company's future evaluations of goodwill. As of December 31, 2004, the Company had recorded goodwill of $2.0 billion related to the merger. 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 their nuclear decommissioning trusts. In accordance with SFAS 115, securities classified as available-for-sale are evaluated to determine whether a decline in fair value below the cost basis is other than temporary. If the decline in fair value is determined to be other than temporary, the cost basis of the security is written down to fair value. The Company considers, among other factors, the length of time and the extent to which the security's fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating investments for impairment. The fair value and unrealized gains and losses of the Company's investments are disclosed in Note 4.

(F)   COMPREHENSIVE INCOME-

Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholder’s equity except those resulting from transactions with FirstEnergy and preferred stockholders. As of December 31, 2004, accumulated other comprehensive loss consisted of unrealized losses on derivative instrument hedges of $2 million and a minimum liability for unfunded retirement benefits of $53 million. As of December 31, 2003, accumulated other comprehensive loss consisted of unrealized losses on derivative instrument hedges of $4 million and a minimum liability for unfunded retirement benefits of $48 million.

(G)   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 carry forward 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.

23

(H)   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 services to the Company. The Company also entered into sale and purchase transactions with affiliates (Met-Ed and Penelec) during the period. Through the BGS auction process, FES is a supplier of power to the Company. The primary affiliated companies transactions are as follows:

	2004		2003		2002
			(In millions)
Operating Revenues:
Wholesale sales-affiliated companies	$	49	$	36	$	18
Operating Expenses:
Service Company support services		95		101		140
Power purchased from other affiliates		--		--		26
Power purchased from FES		71		55		18

FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Company from FESC, a subsidiary of FirstEnergy and a “mutual service company” as defined in Rule 93 of PUHCA. The majority of costs are directly billed or assigned at no more than cost as determined by PUHCA Rule 91. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas that are filed annually with the SEC on Form U-13-60. The current allocation or assignment formulas used and their bases include multiple factor formulas: each company’s proportionate amount of FirstEnergy’s aggregate direct payroll, number of employees, asset balances, revenues, number of customers, other factors and specific departmental charge ratios. Management believes that these allocation methods are reasonable. Intercompany transactions with FirstEnergy and its other subsidiaries are generally settled under commercial terms within thirty days, except for a net $48 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 $62 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 $37 million).

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

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

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	$	68		$	13		$	(79	)	$	(89	)
Increase (decrease) in minimum liability included in other comprehensive income (net of tax)	$	(4	)	$	(145	)		--			--
Assumptions Used to Determine Benefit Obligations As of December 31
Discount rate		6.00	%		6.25	%		6.00	%		6.25	%
Rate of compensation increase		3.50	%		3.50	%
Allocation of Plan Assets As of December 31 Asset Category
Equity securities		68	%		70	%		74	%		71	%
Debt securities		29			27			25			22
Real estate		2			2			--			--
Cash		1			1			1			7
Total		100	%		100	%		100	%		100	%

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

25

	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)	$	7		$	12		$	(20	)	$	5		$	12		$	5

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

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

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

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

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

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

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Pursuant to FSP 106-1 issued January 12, 2004, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 because of a plan amendment during the quarter, which required remeasurement of the plan's obligations. The plan amendment, which increases cost-sharing by employees and retirees effective January 1, 2005, reduced the Company’s postretirement benefit costs by $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 FSP 106-2. The subsidy reduced the Company’s net periodic postretirement benefit costs by $5 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 $46 million. As prescribed by SFAS 87, the Company increased its additional minimum liability by $9 million, offset by a charge to OCI. The balance in AOCL of $53 million (net of $37 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 as of December 31:

	2004				2003
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Long-term debt	$	1,264	$	1,252	$	1,273	$	1,190

The fair values of long-term debt 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.

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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	$	208	$	208	$	200	$	200
-Corporate debt securities		11		11		13		13
		219		219		213		213
Equity securities(1)		80		80		70		70
	$	299	$	299	$	283	$	283

⁽¹⁾ Includes nuclear decommissioning and nuclear fuel disposal 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 held-to-maturity securities and available-for-sale securities. Decommissioning trust investments are classified as available-for-sale. The Company has no securities held for trading purposes. The following table summarizes the amortized cost basis, gross unrealized gains and losses and fair values for decommissioning trust investments as of December 31:

	2004								2003
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
	(In millions)
Debt securities	$	55	$	3	$	--	$	58	$	53	$	4	$	--	$	57
Equity securities		72		10		2		80		54		15		--		69
	$	127	$	13	$	2	$	138	$	107	$	19	$	--	$	126

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	$	119	$	70	$	44
Gross realized gains		15		1		--
Gross realized losses		1		--		--
Interest and dividend income		4		4		4

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

	Less Than 12 Months				12 Months or More				Total
	Fair		Unrealized		Fair		Unrealized		Fair		Unrealized
	Value		Losses		Value		Losses		Value		Losses
	(In millions)
Debt securities	$	3	$	--	$	5	$	--	$	8	$	--
Equity securities		16		2		--		--		16		2
	$	19	$	2	$	5	$	--	$	24	$	2

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 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 $1.4 million, $1.4 million, and $1.2 million for the years 2004, 2003 and 2002, respectively.

As of December 31, 2004, the future minimum lease payments on the Company’s Merrill Creek operating lease, net of reimbursements from subleases, are: $1.7 million, $1.6 million, $1.6 million, $1.6 million and $2.1 million for the years 2005 through 2009, respectively, and $53.0 million for the years thereafter. The Company is recovering its Merrill Creek lease payments, net of reimbursements, through its distribution rates.

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 six 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 variable interests in the remaining six entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants.

As required by FIN 46R, the Company requests on a quarterly basis, the information necessary from these entities to determine whether they are VIEs or whether the Company is the primary beneficiary. The Company has been unable to obtain the requested information, which in most cases, 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 these entities 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 these entities during 2004, 2003 and 2002, were $129 million, $115 million and $107 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, we 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 we 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.

On July 5, 2003, the Company experienced a series of 34.5 kilovolt sub-transmission line faults that resulted in outages on the New Jersey shore. On July 16, 2003, the NJBPU initiated an investigation into the cause of the Company's outages of the July 4, 2003 weekend. The NJBPU selected an SRM to oversee and make recommendations on appropriate courses of action necessary to ensure system-wide reliability. Additionally, pursuant to the stipulation of settlement that was adopted in the NJBPU's Order of March 13, 2003 in its docket relating to the investigation of outages in August 2002, the NJBPU, through an independent auditor working under direction of the NJBPU Staff, undertook a review and focused audit of the Company's Planning and Operations and Maintenance programs and practices (Focused Audit). Subsequent to the initial engagement of the auditor, the scope of the review was expanded to include the outages during July 2003.

Both the independent auditor and the SRM submitted interim reports primarily addressing improvements to be made prior to the next occurrence of peak loads in the summer of 2004. On December 17, 2003, the NJBPU adopted the SRM's interim recommendations related to service reliability. With the assistance of the independent auditor and the SRM, the Company and the NJBPU staff created a Memorandum of Understanding (MOU) that set out specific tasks to be performed by the Company and a timetable for completion. On March 29, 2004, the NJBPU adopted the MOU and endorsed the Company's ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a Stipulation that incorporates the final report of the SRM and the Executive Summary and Recommendation portions of the final report of the Focused Audit. A Final Order in the Focused Audit docket was issued by the NJBPU on July 23, 2004. The Company continues to file compliance reports reflecting activities associated with the MOU and Stipulation.

The Company is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and MTC rates. As of December 31, 2004, the accumulated deferred cost balance totaled approximately $446 million. New Jersey law allows for securitization of the Company's deferred balance upon application by the Company and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. On February 14, 2003, the Company filed for approval of the securitization of the deferred balance. There can be no assurance as to the extent, if any, that the NJBPU will permit such securitization.

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In July 2003,  the NJBPU  announced its JCP&L base electric  rate proceeding decision, which reduced the Company's annual revenues effective August 1, 2003 and disallowed $153 million of deferred energy costs. The NJBPU decision also provided for an interim return on equity of 9.5% on the Company's rate base. The decision ordered that a Phase II proceeding be conducted to review whether the Company is in compliance with current service reliability and quality standards. The NJBPU also ordered that any expenditures and projects undertaken by the Company to increase its system's reliability be reviewed as part of the Phase II proceeding, to determine their prudence and reasonableness for rate recovery. In that Phase II proceeding, the NJBPU could increase the Company's return on equity to 9.75% or decrease it to 9.25%, depending on its assessment of the reliability of JCP&L's service. Any reduction would be retroactive to August 1, 2003. The Company recorded charges to net income for the year ended December 31, 2003, aggregating $185 million ($109 million net of tax) consisting of the $153 million of disallowed deferred energy costs and $32 million of other disallowed regulatory assets. In its final decision and order issued on May 17, 2004, the NJPBU clarified the method for calculating interest attributable to the cost disallowances, resulting in a $5.4 million reduction of the original impairment amount estimated in 2003. The Company filed an August 15, 2003 interim motion for rehearing and reconsideration with the NJBPU and a June 1, 2004 supplemental and amended motion for rehearing and reconsideration. On July 7, 2004, the NJBPU granted limited reconsideration and rehearing on the following issues: (1) deferred cost disallowances (2) the capital structure including the rate of return (3) merger savings, including amortization of costs to achieve merger savings; and (4) decommissioning costs. Management is unable to predict when a decision may be reached by the NJBPU.

On July 16, 2004,  the Company  filed the Phase II petition and testimony with the NJBPU, requesting an increase in base rates of $36 million for the recovery of system reliability costs and a 9.75% return on equity. The filing also requests an increase to the MTC deferred balance recovery of approximately $20 million annually. The Ratepayer Advocate filed testimony on November 16, 2004, the Company submitted rebuttal testimony on January 4, 2005. Settlement conferences are ongoing.

The Company  sells all self-supplied energy (NUGs  and owned generation) to the wholesale market with offsetting credits to its deferred energy balance with the exception of 300 MW from the Company's NUG committed supply currently being used to serve BGS customers pursuant to NJBPU order. The BGS auction for periods beginning June 1, 2004 was completed in February 2004 and new BGS tariffs reflecting the auction results became effective June 1, 2004. The NJBPU decision on the BGS post transition year three process was announced on October 22, 2004, approving with minor modifications the BGS procurement process filed by the Company and the other New Jersey electric distribution companies and authorizing the continued use of NUG committed supply to serve 300 MW of BGS load. The auction for the supply period beginning June 1, 2005 was completed in February 2005.

In accordance with an April 28, 2004 NJBPU order, the Company filed testimony on June 7, 2004 supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, the Company filed an updated TMI-2 decommissioning study (see Note 9 - Asset Retirement Obligation). This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The Ratepayer Advocate filed comments on February 28, 2005.  A schedule for further proceedings has not yet been set.

8.   CAPITALIZATION:

(A)   RETAINED EARNINGS-

In general, the Company’s FMB indenture restricts 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 $41.5 million, net of amounts restricted under the Company’s FMB indenture.

(B)   PREFERRED AND PREFERENCE STOCK-

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

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

Securitized Transition Bonds

On June 11, 2002, JCP&L Transition Funding LLC (Issuer), a wholly owned limited liability company of the Company, sold $320 million of transition bonds to securitize the recovery of the Company’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station.

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The Company does not own, nor did it purchase, any of the transition bonds, which are included in long-term debt on the Company’s Consolidated Balance Sheets. The transition bonds represent obligations only of the Issuer and are collateralized solely by the equity and assets of the Issuer, which consist primarily of bondable transition property. The bondable transition property is solely the property of the Issuer.

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

Other Long-term Debt

The  Company’s  FMB indenture,  which secures all of the Company’s  FMBs, serves 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.

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 $24 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	$	17
2006		208
2007		18
2008		19
2009		25

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 $103.9 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 $129.9 million. The Company expects substantially all nuclear decommissioning costs to be recoverable through regulated rates. Therefore, a regulatory liability of $26 million was recognized upon adoption of SFAS 143. The ARO includes the Company's obligation for the nuclear decommissioning of. 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 $138 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 $43 million.

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

Reconciliation	2004			2003
	(In millions)
Beginning balance as of January 1	$	110		$	104
Accretion		5			6
Revision in estimated cash flows		(42	)		--
Ending balance as of December 31	$	73		$	110

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	$	98
Accretion		6
Ending balance as of December 31	$	104

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 outstanding of $248.5 million from its affiliates with an interest rate of 2.0%

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 $0.2 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. In addition, the Company has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by the Company through a non-bypassable SBC. The Company has accrued liabilities aggregating approximately $47 million 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

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

In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Court issued a decision on July 8, 2004, affirming the decertification of the originally certified class but remanding for certification of a class limited to those customers directly impacted by the outages of transformers in Red Bank, New Jersey. On September 8, 2004, the New Jersey Supreme Court denied the motions filed by plaintiffs and JCP&L for leave to appeal the decision of the Appellate Court. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of December 31, 2004.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. On April 5, 2004, the U.S. - Canada Power System Outage Task Force released its final report on the outages. In the final report, the Task Force concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contains 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations relate to broad industry or policy matters while one, including subparts, relates to activities the Task Force recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which are consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy certified to NERC on June 30, 2004, completion of various reliability recommendations and further received independent verification of completion status from a NERC verification team on July 14, 2004 with minor exceptions noted by FirstEnergy (see Note 9). FirstEnergy’s implementation of these recommendations included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these initiatives already were in process, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its operations or financial results. FirstEnergy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. FirstEnergy has not accrued a liability as of December 31, 2004 for any expenditures in excess of those actually incurred through that date.

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 herein.

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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.

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

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

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

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

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

In March 2004, the FASB ratified the final consensus on Issue 03-16. EITF 03-16 requires that an investment in a limited liability company that maintains a "specific ownership account" for each investor should be viewed as similar to an investment in a limited partnership for determining whether the cost or equity method of accounting should be used. The equity method of accounting is generally required for investments that represent more than a three to five percent interest in a limited partnership. EITF 03-16 was adopted by 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):

	March 31,		June 30,		September 30,		December 31,
Three Months Ended	2004		2004		2004		2004(a)
	(In millions)
Operating Revenues	$	498.1	$	549.6	$	706.6	$	452.7
Operating Expenses and Taxes		466.1		494.7		634.5		427.8
Operating Income		32.0		54.9		72.1		24.9
Other Income		1.5		1.1		2.0		3.2
Net Interest Charges		20.1		19.2		21.8		18.9
Net Income	$	13.4	$	36.8	$	52.3	$	9.2
Earnings on Common Stock	$	13.3	$	36.7	$	52.2	$	8.9

	March 31,		June 30,			September 30,		December 31,
Three Months Ended	2003		2003			2003		2003
	(In millions)
Operating Revenues	$	657.0	$	542.8		$	741.3	$	418.6
Operating Expenses and Taxes		581.6		564.5			653.8		413.0
Operating Income (Loss)		75.4		(21.7	)		87.5		5.6
Other Income		1.2		2.3			0.6		3.0
Net Interest Charges		22.5		22.4			20.5		20.4
Net Income (Loss)	$	54.1	$	(41.8	)	$	67.6	$	(11.8	)
Earnings (Loss) Applicable to Common Stock	$	53.9	$	(41.4	)	$	67.4	$	(11.8	)

^(a) Net income for the quarter ended December 31, 2004 includes an adjustment relating to periods prior to October 1, 2004, that decreased amortization expense and increased regulatory assets by $3.8 million ($2.2 million after tax). The adjustment corrects the accumulated amortization of the MTC deferred balance due to a revised MTC Tariff that became effective on August 1, 2003. Management concluded that the adjustment was not material to the reported results of operations for any quarter of 2003 and 2004, nor was it material to the consolidated balance sheets and consolidated statements of cash flows for any of those quarters.

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