METROPOLITAN EDISON COMPANY

2005 ANNUAL REPORT TO STOCKHOLDERS

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

Contents	Page
Glossary of Terms	i-ii
Report of Independent Registered Public Accounting Firm	1
Selected Financial Data	2
Management's Discussion and Analysis	3-14
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 Metropolitan Edison Company and its affiliates:

ATSI	American Transmission Systems, Inc., owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an affiliated Ohio electric utility
Companies	OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec
FES	FirstEnergy Solutions Corp., provides energy-related products and services
FESC	FirstEnergy Service Company, provides legal, financial, and other corporate support services
FirstEnergy	FirstEnergy Corp., a public utility holding company
GPU	GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on November 7, 2001
GPUS	GPU Service Company, previously provided corporate support services
JCP&L	Jersey Central Power & Light Company, an affiliated New Jersey electric utility
Met-Ed	Metropolitan Edison Company
NGC	FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities
OE	Ohio Edison Company, an affiliated Ohio electric utility
Penelec	Pennsylvania Electric Company, an affiliated Pennsylvania electric utility
Penn	Pennsylvania Power Company, an affiliated Pennsylvania electric utility
TE	The Toledo Edison Company, an affiliated Ohio electric utility
The following abbreviations and acronyms are used to identify frequently used terms in this report:
ALJ	Administrative Law Judge
AOCL	Accumulated Other Comprehensive Loss
APB	Accounting Principles Board
APB 29	APB Opinion No. 29, "Accounting for Nonmonetary Transactions"
ARB	Accounting Research Bulletin
ARB 43	ARB No. 43, "Restatement and Revision of Accounting Research Bulletins"
ARO	Asset Retirement Obligation
CTC	Competitive Transition Charge
ECAR	East Central Area Reliability Coordination
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 04-13	EITF Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty
EPACT	Energy Policy Act of 2005
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
FIN 46R	FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities"
FIN 47	FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"
FMB	First Mortgage Bonds
FSP	FASB Staff Position
FSP 106-1	FASB Staff Position No.106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003"
FSP 106-2	FASB Staff Position No.106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, and Modernization Act of 2003"
FSP 115-1 and FAS 124-1	FASB Staff Position No. 115-1 and FAS 124-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"
GAAP	Accounting Principles Generally Accepted in the United States
IRS	Internal Revenue Service
KWH	Kilowatt-hours
Medicare Act	Medicare Prescription Drug, Improvement and Modernization Act of 2003
MEIUG	Met-Ed Industrial Users Group
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service
NERC	North American Electric Reliability Council
NUG	Non-Utility Generation

i

GLOSSARY OF TERMS (Cont’d)

OCA	Office of Consumer Advocate
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
OSBA	Office of Small Business Advocate
OTS	Office of Trial Staff
PICA	Penelec Industrial Customer Association
PJM	PJM Interconnection L. L. C.
PLR	Provider of Last Resort
PPUC	Pennsylvania Public Utility Commission
PRP	Potentially Responsible Party
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act
S&P	Standard & Poor's Ratings Service
SEC	United States Securities and Exchange Commission
SFAC	Statement of Financial Accounting Concepts
SFAC 7	SFAC No. 7, "Using Cash Flow Information and Present Value in Accounting Measurements"
SFAS	Statement of Financial Accounting Standards
SFAS 71	SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
SFAS 87	SFAS No. 87, "Employers' Accounting for Pensions"
SFAS 106	SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions"
SFAS 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 142	SFAS No. 142, "Goodwill and Other Intangible Assets"
SFAS 143	SFAS No. 143, "Accounting for Asset Retirement Obligations"
SFAS 144	SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"
SFAS 151	SFAS No. 151, "Inventory Costs - an amendment of ARB No. 43, Chapter 4"
SFAS 153	SFAS No. 153, "Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29"
SFAS 154	SFAS No. 154, "Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3"
TMI-1	Three Mile Island Unit 1
TMI-2	Three Mile Island Unit 2
VIE	Variable Interest Entity

ii

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Metropolitan Edison Company:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes present fairly, in all material respects, the financial position of Metropolitan Edison Company and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2(G) and Note 9 to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations as of January 1, 2003 and conditional asset retirement obligations as of December 31, 2005.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 27, 2006

1

The following selected financial data should be read in conjunction with, and is qualified in its entirety by reference to, the sections entitled “Management’s Discussion and Analysis of Results of Operations and Financial Condition” and with our consolidated financial statements and the “Notes to Consolidated Financial Statements.” Our Consolidated Statements of Income are not necessarily indicative of future conditions or results of operations.

METROPOLITAN EDISON COMPANY
SELECTED FINANCIAL DATA
													Nov 7 -		Jan 1-
	2005			2004			2003			2002			Dec. 31, 2001		Nov. 6, 2001
	(Dollars in thousands)
GENERAL FINANCIAL INFORMATION:
Operating Revenues	$	1,176,418		$	1,070,847		$	969,788		$	986,608		$	143,760	$	824,556
Operating Income	$	63,106		$	86,197		$	83,938		$	91,271		$	17,367	$	102,247
Income Before Cumulative Effect
of Accounting Changes	$	45,919		$	66,955		$	60,953		$	63,224		$	14,617	$	62,381
Net Income	$	45,609		$	66,955		$	61,170		$	63,224		$	14,617	$	62,381
Total Assets	$	2,917,687		$	3,243,546		$	3,472,709		$	3,564,716		$	3,607,187
CAPITALIZATION AS OF DECEMBER 31:
Common Stockholder’s Equity	$	1,316,099		$	1,285,419		$	1,292,667		$	1,315,586		$	1,288,953
Company-Obligated Mandatorily
Preferred Securities		-			-			-			92,409			92,200
Long-Term Debt and Other Long-Term Obligations		591,888			701,736			636,301			538,790			583,077
Total Capitalization	$	1,907,987		$	1,987,155		$	1,928,968		$	1,946,785		$	1,964,230
CAPITALIZATION RATIOS:
Common Stockholder’s Equity		69.0	%		64.7	%		67.0	%		67.6	%		65.6%
Company-Obligated Mandatorily
Preferred Securities		-			-			-			4.7			4.7
Long-Term Debt and Other Long-Term Obligations		31.0			35.3			33.0			27.7			29.7
Total Capitalization		100.0	%		100.0	%		100.0	%		100.0	%		100.0%
DISTRIBUTION KWH DELIVERIES (Millions):
Residential		5,399			5,071			4,900			4,738			793		3,712
Commercial		4,491			4,251			4,034			3,991			652		3,203
Industrial		4,083			4,042			4,047			3,972			662		3,506
Other		36			33			36			35			6		27
Total		14,009			13,397			13,017			12,736			2,113		10,448
CUSTOMERS SERVED:
Residential		471,333			464,287			455,073			448,334			442,763
Commercial		60,413			59,495			58,825			58,010			57,278
Industrial		1,859			1,868			1,906			1,936			1,961
Other		721			730			732			728			819
Total		534,326			526,380			516,536			509,008			502,821
NUMBER OF EMPLOYEES:		678			651			659			*			*		*
*   For years prior to 2003 Met-Ed's employees were employed by GPU Service Company.

2

METROPOLITAN EDISON COMPANY

Management’s Discussion and Analysis of

Results of Operations and Financial Condition

Forward-looking Statements. 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, the continued ability of our regulated utilities to collect transition and other charges or to recover increased transmission costs, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), the repeal of PUHCA and the legal and regulatory changes resulting from the implementation of the EPACT, the uncertainty of the timing and amounts of the capital expenditures (including that such amounts could be higher than anticipated) or levels of emission reductions related to the settlement agreement resolving the New Source Review litigation, adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or operating permits, fines or other enforcement actions and remedies) of governmental investigations and oversight, including by the Securities and Exchange Commission, the United States Attorney's Office, the Nuclear Regulatory Commission and the Pennsylvania Public Utility Commission as disclosed in our Securities and Exchange Commission filings, the continuing availability and operation of generating units, the ability of generating units to continue to operate at, or near full capacity, our inability to accomplish or realize anticipated benefits from strategic goals (including employee workforce factors), the anticipated benefits from our voluntary pension plan contributions, our ability to improve electric commodity margins and to experience growth in the distribution business, our ability to access the public securities and other capital markets and the cost of such capital, the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the August 14, 2003 regional power outage, the risks and other factors discussed from time to time in our Securities and Exchange Commission filings, and other similar factors. Also, a credit rating should not be viewed as a recommendation to buy, sell or hold securities and may be revised or withdrawn by a rating agency at any time. We expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events, or otherwise.

Results of Operations

Net income decreased to $46 million in 2005 compared to $67 million in 2004, primarily due to higher purchased power costs, general taxes, and other operating costs, partially offset by higher operating revenues and other income. Net income increased to $67 million in 2004, compared to $61 million in 2003, due to higher operating revenues partially offset by higher purchased power costs and other operating costs.

Operating Revenues

Operating revenues increased by $106 million, or 9.9%, in 2005 primarily as a result of higher sales levels. Retail generation revenues increased by $47 million due to an 8.8% increase in KWH sales. Generation sales increased in all customer sectors (industrial - 15.5%, residential - 6.5% and commercial - 6.5%) largely due to unusually warm summer temperatures in 2005 and reduced customer shopping. Industrial customer shopping decreased by 11.1 percentage points in 2005 from 2004. Revenues from distribution throughput increased by $25 million primarily due to a 4.6% increase in KWH deliveries which reflected the effect of the warmer summer temperatures and slightly higher composite unit prices. The higher KWH deliveries were also primarily responsible for increased transmission revenues of $30 million. In 2005, other operating revenues included a $4 million payment received under a contract provision associated with the prior sale of TMI Unit 1. Under the contract, additional payments are received if subsequent energy prices rise above specific levels and are credited to our customers, resulting in no net impact to earnings.

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

3

Changes in electric generation sales and distribution deliveries in 2005 and 2004 are summarized in the following table:

Changes in KWH Sales	2005			2004
Increase (Decrease)
Electric Generation:
Retail		8.8	%		11.8	%
Wholesale		5.3	%		209.1	%
Total Electric Generation Sales		8.8	%		12.0	%
Distribution Deliveries:
Residential		6.5	%		3.5	%
Commercial		5.6	%		5.4	%
Industrial		1.0	%		(0.1	)%
Total Distribution Deliveries		4.6	%		2.9	%

Operating Expenses and Taxes

Total operating expenses and taxes increased by $129 million, or 13.1% in 2005, and by $99 million in 2004. The following table presents changes from the prior year expense category:

Operating Expenses and Taxes - Changes	2005			2004
Increase (Decrease)	(In millions)
Fuel costs	$	1		$	-
Purchased power costs		66			64
Other operating costs		60			32
Provision for depreciation		1			(3	)
Amortization of regulatory assets		7			8
General taxes		4			3
Income taxes		(10	)		(5	)
Total operating expenses and taxes	$	129		$	99

Purchased power costs increased by $66 million in 2005, compared with 2004. The increase reflected a 7.3% increase in KWH purchases in order to meet higher retail generation sales requirements, partially offset by the effect of lower unit costs. NUG contract purchases were also $33 million higher in 2005. Other operating costs increased by $60 million in 2005 primarily due to higher transmission expenses necessary to support the increased KWH sales as discussed above. General taxes increased by $4 million primarily due to increased gross receipt taxes from the increased retail generation sales in 2005 as compared to 2004. Income taxes decreased due to lower taxable income in 2005 as compared to 2004.

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

Other Income

Other income increased by $2 million in 2005 as compared to 2004 primarily due to a gain from the sale of the Easton Service Center property. Other income increased $4 million in 2004, compared to 2003, due to a $2 million increase in the return on CTC stranded generation regulatory assets and $2 million of interest income on federal income tax refunds.

Net Interest Charges

Interest on long-term debt decreased by $4 million in 2005 due to a reduction in long-term debt outstanding. This decrease was partially offset by higher interest expenses resulting from increased intercompany loans through the money pool as discussed further below.

4

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

Cumulative Effect of Accounting Change

Results in 2005 include an after-tax charge to net income of $310,000 recorded upon the adoption of FIN 47 in December 2005. We identified applicable legal obligations as defined under the new standard at our substation control rooms, service center buildings, line shops and office buildings, identifying asbestos as the primary conditional ARO. As a result of adopting FIN 47, we recorded a conditional ARO liability of $628,000 (including accumulated accretion for the period from the date the liability was incurred to the date of adoption), an asset retirement cost of $148,000 (recorded as part of the carrying amount of the related long-lived asset) and accumulated depreciation of $50,000.

Upon adoption of SFAS 143 in the first quarter of 2003, we recorded an after-tax credit to net income of $217,000. The cumulative effect adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $371,000 increase to income, or $217,000 net of income taxes.

Capital Resources and Liquidity

Our cash requirements in 2005 for operating expenses, construction expenditures and scheduled debt maturities were met with a combination of cash from operations and funds from the capital markets. We plan to issue long-term debt during 2006 to fund maturing long-term debt obligations. During 2006 and thereafter, we expect to meet our contractual obligations with a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

As of December 31, 2005, we had cash and cash equivalents of $120,000, which remained unchanged from December 31, 2004.

Cash Flows From Operating Activities

Cash flows provided from operating activities totaled $125 million in 2005, $74 million in 2004 and $132 million in 2003. The sources of these changes are as follows:

Operating Cash Flows	2005			2004			2003
	(In millions)
Cash earnings (1)	$	125		$	117		$	148
Pension trust contribution(2)		(25	)		(23	)		-
Working capital		25			(20	)		(16	)
Net cash provided  from operating activities	$	125		$	74		$	132

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

⁽²⁾Pension trust contributions in 2005 and 2004 are net of $11 million and $16 million of income tax benefits, respectively.

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	2005			2004			2003
	(In millions)
Net Income (GAAP)	$	46		$	67		$	61
Non-Cash Charges (Credits):
Provision for depreciation		43			41			44
Amortization of regulatory assets		112			106			98
Deferred costs recoverable as regulatory assets		(68	)		(100	)		(103	)
Deferred income taxes and investment tax credits*		(2	)		3			46
Other non-cash expenses		(6	)		-			2
Cash earnings (Non-GAAP)	$	125		$	117		$	148

* Excludes $16 million of deferred tax benefits from pension contributions in 2004.

5

Net cash provided from operating activities increased $51 million in 2005 as compared to 2004 resulting from increases of $45 million from working capital changes and $8 million in cash earnings described under "Results of Operations", partially offset by a $2 million after-tax voluntary pension trust contribution increase. The increase from working capital was principally due a $144 million increase in cash provided from the settlement of receivables partially offset by an $86 million cash reduction in payables.

Net cash provided from operating activities decreased $58 million during 2004, compared with 2003. The decrease consisted of lower cash earnings of $31 million, a $23 million after-tax voluntary pension trust contribution in 2004, and a $4 million decrease from changes in working capital. The decrease in cash earnings reflects changes in deferred income tax expense partially offset by other changes as described under "Results of Operations." The decrease in working capital was principally due to changes in accounts receivables partially offset by increases in accounts payable balances.

Cash Flows From Financing Activities

Net cash used for financing activities of $32 million in 2005 compares to net cash provided from financing activities of $11 million in 2004. The net change of $43 million reflects an $89 million decrease in long-term debt financing offset by a $45 million increase in short-term borrowings and a $1 million decrease in common stock dividend payments to FirstEnergy. Net cash provided from financing activities of $11 million in 2004 compares to net cash used for financing activities of $88 million used in 2003. The $99 million net change reflects a $64 million decrease in long-term debt redemptions and a $38 million increase in short-term borrowings partially offset by a $3 million increase in common stock dividend payments to FirstEnergy.

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

Securities Issued or Redeemed	2005		2004		2003
	(In millions)
New Issues:
Pollution control notes	$	29	$	-	$	-
Secured notes		-		-		248
Unsecured notes		-		247		-
	$	29	$	247	$	248
Redemptions:
FMB	$	66	$	90	$	260
Subordinated debentures		-		100		-
Other		-		6		-
	$	66	$	196	$	260
Short-term Borrowings, net	$	60	$	15	$	(23	)

We had approximately $17 million of cash and temporary investments (which included short-term notes receivable from associated companies) and approximately $140 million of short-term indebtedness as of December 31, 2005. We have authorization from the SEC to incur short-term debt of up to $250 million and authorization from the PPUC to incur money pool borrowings of up to $300 million. In addition, we have $80 million of available accounts receivable financing facilities as of December 31, 2005 from Met-Ed Funding, our wholly owned subsidiary. As a separate legal entity with separate creditors, Met-Ed Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to us.

                    Under the terms of our senior note indenture, FMB may not be issued as long as senior notes are outstanding. As of December 31, 2005, we had the capability to issue $665 million of additional senior notes based upon FMB collateral. We have no restrictions on the issuance of preferred stock.

On June 14, 2005, we, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Penelec, FES and ATSI, as Borrowers, entered into a syndicated $2 billion five-year revolving credit facility with a syndicate of banks. Borrowings under the facility are available to each Borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment expiration date, as the same may be extended. Our borrowing limit under the facility is $250 million.

Under the revolving credit facility, borrowers may request the issuance of letters of credit expiring up to one year from the date of issuance. The stated amount of outstanding letters of credit will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit. Total unused borrowing capability under existing credit facilities and accounts receivable financing facilities totaled $330 million as of December 31, 2005.

The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%. As of December 31, 2005, our debt to total capitalization as defined under the revolving credit facility was 39%.

6

The facility does not contain any provisions that either restrict our ability to borrow or accelerate repayment of outstanding advances as a result of any change in our credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to our credit ratings.

We have the ability to borrow from our regulated affiliates and FirstEnergy to meet our short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in 2005 was 3.24%.

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the Companies to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the Companies by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter of 2005. On December 23, 2005, Fitch revised its rating outlook on FirstEnergy and the Companies to positive from stable. Fitch stated that the revision to FirstEnergy's outlook resulted from improved performance of its generating fleet and ongoing debt reduction.

Our access to capital markets and costs of financing are dependent on the ratings of our securities and that of FirstEnergy. The following table displays FirstEnergy’s and Met-Ed’s securities ratings as of December 31, 2005. The ratings outlook from S&P on all securities is stable. The ratings outlook from Moody’s & Fitch on all securities is positive.

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

Cash Flows From Investing Activities

Cash used for investing activities totaled $94 million in 2005 and $85 million in 2004. The increase is primarily the result of an increase in property additions partially offset by an increase in loan repayments from associated companies.

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

Our capital spending for the period 2006 through 2010 is expected to be about $365 million for energy delivery related improvements, of which approximately $81 million applies to 2006. The capital spending is primarily for property additions supporting the distribution of electricity.

Contractual Obligations

As of December 31, 2005, our estimated cash payments under existing contractual obligations that we consider firm obligations are as follows:

					2007-		2009-
Contractual Obligations	Total		2006		2008		2010		Thereafter
	(In millions)
Long-term debt (1)	$	692	$	100	$	50	$	100	$	442
Short-term borrowings		140		140		-		-		-
Operating leases (2)		63		4		6		7		46
Purchases (3)		3,080		491		996		842		751
Total	$	3,975	$	735	$	1,052	$	949	$	1,239

 ⁽¹⁾Amounts reflected do not include interest on long-term debt.

 ⁽²⁾Operating lease payments are net of reimbursements from subleasees (see Note 5 - Leases).

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

7

Market Risk Information

We use various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. Our Risk Policy Committee, comprised of members of senior management, provides general oversight to risk management activities throughout the company.

Commodity Price Risk

We are exposed to market risk primarily due to fluctuations in electricity, energy transmission, natural gas, coal and emission allowance prices. To manage the volatility relating to these exposures, we use a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. All derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of our derivative hedging contracts qualify for the normal purchase and normal sale exception under SFAS 133 and are therefore excluded from the table below. Contracts that are not exempt from such treatment include power purchase agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Act of 1978. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs. The change in the fair value of commodity derivative contracts related to energy production during 2005 is summarized in the following table:

Increase (Decrease) in the Fair Value of Derivative Contracts	Non-Hedge			Hedge		Total
	(In millions)
Change in the fair value of commodity derivative contracts
Outstanding net liability as of January 1, 2005	$	(318	)	$	-	$	(318	)
New contract value when entered		-			-		-
Additions/Changes in value of existing contracts		283			-		283
Change in techniques/assumptions		-			-		-
Settled contracts		61			-		61
Net Assets - Derivatives Contracts as of December 31, 2005(1)	$	26		$	-	$	26
Impact of Changes in Commodity Derivative Contracts(2)
Income Statement Effects (Pre-Tax)	$	-		$	-	$	-
Balance Sheet Effects:
OCI (Pre-Tax)	$	-		$	-	$	-
Regulatory Asset (net)	$	(344	)	$	-	$	(344	)

⁽¹⁾ Includes $26 million in non-hedge commodity derivative contracts, which are offset by a regulatory liability.

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

Derivatives are included on the Consolidated Balance Sheet as of December 31, 2005 as follows:

	Non-Hedge			Hedge		Total
	(In millions)
Current-
Other Assets	$	-		$	-	$	-
Other liabilities		-			-		-
Non-Current-
Other Deferred Charges		28			-		28
Other noncurrent liabilities		(2	)		-		(2	)
Net assets	$	26		$	-	$	26

8

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

Source of Information
- Fair Value by Contract Year	2006			2007			2008			2009			2010			Thereafter		Total
	(In millions)
Prices actively quoted(1)	$	(3	)	$	(21	)	$	-		$	-		$	-		$	-	$	(24	)
Other external sources(2)		11			4			5			-			-			-		20
Prices based on models		-			-			(28	)		(21	)		(14	)		93		30
Total(3)	$	8		$	(17	)	$	(23	)	$	(21	)	$	(14	)	$	93	$	26

      ⁽¹⁾Exchange traded.

      ⁽²⁾Broker quote sheets.

      ⁽³⁾Includes $26 million in non-hedge commodity derivative contracts, which are offset by a regulatory liability.

We perform sensitivity analyses to estimate our exposure to the market risk of our commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on both our trading and nontrading derivative instruments would not have had a material effect on our consolidated financial position or cash flows as of December 31, 2005. We estimate that if energy commodity prices experienced an adverse 10% change, net income for the next twelve months would not change, as the prices for all commodity positions are already above the contract price caps.

Interest Rate Risk

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

Comparison of Carrying Value to Fair Value

												There-						Fair
Year of Maturity	2006			2007			2008	2009	2010			after			Total			Value
	(Dollars in millions)
Assets
Investments Other Than Cash and Cash Equivalents-
Fixed Income												$	93		$	93		$	93
Average interest rate													5.5	%		5.5	%
Liabilities
Long-term Debt and Other Long-Term Obligations:
Fixed rate	$	100		$	50				$	100		$	414		$	664		$	654
Average interest rate		5.7	%		5.9	%				4.5	%		4.9	%		5.1	%
Variable rate												$	28		$	28		$	28
Average interest rate													3.1	%		3.1	%
Short-term Borrowings	$	140													$	140		$	140
Average interest rate		4.0	%													4.0	%

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $142 million and $134 million as of December 31, 2005 and 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $14 million reduction in fair value as of December 31, 2005 (see Note 4 - Fair Value of Financial Instruments).

9

Outlook

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

Regulatory Matters

Regulatory assets are costs which have been authorized by the PPUC and the FERC for recovery from customers in the future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered under the provisions of our transition plan and rate restructuring plan.

As of December 31, 2005, our regulatory deferrals pursuant to the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation are $333 million.

 Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sales agreement and a portion from contracts with unaffiliated third party suppliers, including NUGs. Assuming continuation of these existing contractual arrangements, the available supply represents approximately 100% of the combined retail sales obligations of Met-Ed and Penelec in 2006 and 2007; almost 100% for 2008; and approximately 85% for 2009 and 2010. Met-Ed and Penelec are authorized to defer any excess of NUG contract costs over current market prices. Under the terms of the wholesale agreement with FES, FES retains the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their contracts with NUGs and other unaffiliated suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR energy costs during the term of the agreement with FES. The wholesale agreement with FES is automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. On November 1, 2005, FES and the other parties thereto amended the agreement to provide FES the right over the next year to terminate the agreement at any time upon 60 days notice. If the wholesale power agreement were terminated or modified, Met-Ed and Penelec would need to satisfy the portion of their PLR obligations currently supplied by FES from unaffiliated suppliers at prevailing prices, which are likely to be higher than the current price charged by FES under the agreement and, as a result, Met-Ed’s and Penelec’s purchased power costs could materially increase. If Met-Ed and Penelec were to replace the FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer support an investment grade rating for its fixed income securities. Met-Ed and Penelec are in the process of preparing a comprehensive rate filing that will address a number of transmission, distribution and supply issues and is expected to be filed with the PPUC in the second quarter of 2006. That filing will include, among other things, a request for appropriate regulatory action to mitigate adverse consequences from any future reduction, in whole or in part, in the availability to Met-Ed and Penelec of supply under the existing FES agreement. There can be no assurance, however, that if FES ultimately determines to terminate, or significantly modify the agreement, timely regulatory relief will be granted by the PPUC or, to the extent granted, adequate to mitigate such adverse consequences.

On January 12, 2005, we filed a request with the PPUC for deferral of transmission-related costs beginning January 1, 2005, estimated to be approximately $4 million per month. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association have all intervened in the case. To date no hearing schedule has been established, and we have not yet implemented deferral accounting for these costs.

In May 2004, the PPUC issued an order approving revised reliability benchmarks and standards, including revised benchmarks and standards for the Company. We filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004, due to their implementation of automated outage management systems following restructuring. On December 30, 2005, the ALJ recommended that the PPUC adopt the Joint Petition for Settlement among the parties involved in our request to amend the distribution reliability benchmarks, thereby eliminating the need for full litigation. The ALJ’s recommendation, adopting the revised benchmarks and standards was approved by the PPUC on February 9, 2006.

See Note  7 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania including a more detailed discussion of reliability initiatives, including actions by the PPUC, that impact us.

10

Environmental Matters

We accrue environmental liabilities only when we can conclude that it is probable that we have an obligation for such costs and can reasonably determine the amount of such costs. Unasserted claims, are reflected in our determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

On December 1, 2005, FirstEnergy issued a comprehensive report to shareholders regarding air emissions regulations and an assessment of our future risks and mitigation efforts.

We have been named as a PRP at waste disposal sites which may require cleanup under the Comprehensive Environmental Responsive, Comprehension and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantial and subject to dispute; however, federal law provides that PRPs for a particular site are 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, 2005, based on estimates of the total costs of cleanup, our proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $49,000 have been accrued through December 31, 2005.

See Note 11(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to our normal business operations pending against us. The other material items not otherwise discussed above are described in Note 11 to the consolidated financial statements.

Critical Accounting Policies

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

Goodwill

In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, we evaluate our goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If an impairment were indicated, we recognize a loss - calculated as the difference between the implied fair value of our goodwill and the carrying value of the goodwill. Our annual review was completed in the third quarter of 2005, with no impairment of goodwill indicated. The forecasts used in our evaluation of goodwill reflect operations consistent with our general business assumptions. Unanticipated changes in those assumptions could have a significant effect on our future evaluations of goodwill. In the year ended December 31, 2005, we adjusted goodwill to reverse pre-merger tax accruals due to the final resolution of tax contingencies related to the GPU acquisition. As of December 31, 2005, we had approximately $864 million of goodwill.

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.

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.

11

Pension and Other Postretirement Benefits Accounting

Our reported costs of providing non-contributory defined pension benefits and post employment 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, 2005 to 5.75% from 6.00% and 6.25% used as of December 31, 2004 and 2003, respectively.

Our assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by our pension trusts. In 2005, 2004 and 2003, plan assets actually earned $325 million or 8.2%, $415 million or 11.1% and $671 million or 24.2%, respectively. Our pension costs in 2005, 2004 and 2003 were computed using an assumed 9.0% rate of return on plan assets which generated $345 million, $286 million and $248 million expected returns on plan assets, respectively. The 2005 expected return was based upon projections of future returns and our pension trust investment allocation of approximately 63% equities, 33% bonds, 2% real estate and 2% cash. The gains or losses generated as a result of the difference between expected and actual return on plan assets are deferred and amortized and will increase or decrease future net periodic pension expense, respectively.

In the fourth quarter of 2005, FirstEnergy made a $500 million voluntary contribution to its pension plan (our share was $36 million). As a result of our voluntary contribution and the increased market value of pension plan assets, we recognized a prepaid benefit cost of $89 million as of December 31, 2005. As prescribed by SFAS 87, we eliminated our additional minimum liability of $71 million. In addition, the entire AOCL balance was credited by $42 million (net of $29 million of deferred taxes) as the fair value of trust assets exceeded the accumulated benefit obligation as of December 31, 2005.

Health care cost trends have significantly increased and will affect future OPEB costs. The 2005 and 2004 composite health care trend rate assumptions are approximately 9-11%, 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. The effect on Met-Ed's portion of pension and OPEB costs from changes in key assumptions are as follows:

Increase in Costs from Adverse Changes in Key Assumptions
Assumption	Adverse Change		Pension		OPEB		Total
	(In millions)
Discount rate		Decrease by 0.25%	$	0.7	$	0.3	$	1.0
Long-term return on assets		Decrease by 0.25%	$	1.0	$	0.2	$	1.2
Health care trend rate		Increase by 1%		na	$	1.4	$	1.4

Long-Lived Assets

In accordance with SFAS 144, we periodically evaluate our long-lived assets (principally goodwill) 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).

12

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.

Asset Retirement Obligations

In accordance with SFAS 143 and FIN 47, we recognize an ARO for the future decommissioning of our nuclear power plants and future remediation of other environmental liabilities associated with all of our long-lived assets. The ARO liability represents an estimate of the fair value of our current obligation related to nuclear decommissioning and the retirement or remediation of environmental liabilities 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 and environmental remediation ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants' current license; settlement based on an extended license term and expected remediation dates.

New Accounting Standards and Interpretations Adopted

FSP FAS 115-1 and FAS 124-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

Issued in November 2005, FSP 115-1 and FAS 124-1 addresses the determination as to when an investment is considered impaired, whether that impairment is other than temporary, and the measurement of an impairment loss. The FSP finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. This FSP will (1) nullify certain requirements of Issue 03-1 and supersedes EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when the impairment is deemed other than temporary, even if a decision to sell has not been made, and (3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after September 15, 2005. The FSP requires prospective application with an effective date for reporting periods beginning after December 15, 2005. We are currently evaluating this FSP and any impact on our investments.

EITF Issue 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"

In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, we will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006.

SFAS 154 - “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in the Consolidated Statements of Income. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We adopted this Statement effective January 1, 2006.

13

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

In December 2004, the FASB issued SFAS 153 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 January 1, 2006 for us. This FSP is not expected to have a material impact on our financial statements.

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

In November 2004, the FASB issued SFAS 151 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 us beginning January 1, 2006. We do not expect this statement to have a material impact on the financial statements.

14

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2005			2004			2003
				(In thousands)
OPERATING REVENUES (Note 2(I))	$	1,176,418		$	1,070,847		$	969,788
OPERATING EXPENSES AND TAXES:
Fuel		1,497			39			-
Purchased power (Note 2(I))		620,764			554,949			491,346
Other operating costs (Note 2(I))		249,945			190,401			157,986
Provision for depreciation		42,684			41,161			44,160
Amortization of regulatory assets		112,117			105,675			97,784
General taxes		73,989			70,457			67,207
Income taxes		12,316			21,968			27,367
Total operating expenses and taxes		1,113,312			984,650			885,850
OPERATING INCOME		63,106			86,197			83,938
OTHER INCOME (net of income taxes)		27,098			25,537			21,782
NET INTEREST CHARGES:
Interest on long-term debt		36,804			40,630			36,657
Allowance for borrowed funds used during construction		(370	)		(278	)		(323	)
Deferred interest		-			-			(1,187	)
Other interest expense		7,851			4,427			5,841
Subsidiary's preferred stock dividend requirements		-			-			3,779
Net interest charges		44,285			44,779			44,767
INCOME BEFORE CUMULATIVE EFFECT
OF ACCOUNTING CHANGES		45,919			66,955			60,953
Cumulative effect of accounting changes (net of income taxes
(benefit) of ($220,000) and $154,000, respectively) (Note 2(G))		(310	)		-			217
NET INCOME	$	45,609		$	66,955		$	61,170
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

15

METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31,		2005		2004
	(In thousands)
ASSETS
UTILITY PLANT:
In service		$	1,856,425	$	1,800,569
Less - Accumulated provision for depreciation			721,566		709,895
			1,134,859		1,090,674
Construction work in progress			20,437		21,735
			1,155,296		1,112,409
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts			234,854		216,951
Long-term notes receivable from associated companies			11,337		10,453
Other			29,678		34,767
			275,869		262,171
CURRENT ASSETS:
Cash and cash equivalents			120		120
Notes receivable from associated companies			16,530		18,769
Receivables-
Customers (less accumulated provision of $4,352,000 and $4,578,000
respectively, for uncollectible accounts)			129,854		119,858
Associated companies			37,267		118,245
Other			8,780		15,493
Prepayments and other			7,912		11,057
			200,463		283,542
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill			864,438		869,585
Regulatory assets			309,556		691,401
Prepaid pension costs			89,005		-
Other			23,060		24,438
			1,286,059		1,585,424
		$	2,917,687	$	3,243,546
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity		$	1,316,099	$	1,285,419
Long-term debt and other long-term obligations			591,888		701,736
			1,907,987		1,987,155
CURRENT LIABILITIES:
Currently payable long-term debt			100,000		30,435
Short-term borrowings (Note 10)-
Associated companies			140,240		80,090
Accounts payable-
Associated companies			37,220		88,879
Other			27,507		26,097
Accrued taxes			17,911		11,957
Accrued interest			9,438		11,618
Other			24,274		23,076
			356,590		272,152
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			344,929		305,389
Accumulated deferred investment tax credits			10,043		10,868
Power purchase contract loss liability			1,578		349,980
Nuclear fuel disposal costs			39,567		38,408
Asset retirement obligation			142,020		132,887
Retirement benefits			57,809		82,218
Other			57,164		64,489
			653,110		984,239
COMMITMENTS AND CONTINGENCIES
(Notes 5 and 11)		$	2,917,687	$	3,243,546
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.

16

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31,	2005			2004
	(Dollars in thousands, except per  share amounts)
COMMON STOCKHOLDER'S EQUITY:
Common stock, without par value, authorized 900,000 shares
859,500 shares outstanding	$	1,287,093		$	1,289,943
Accumulated other comprehensive loss (Note 2(F))		(1,569	)		(43,490	)
Retained earnings (Note 8(A))		30,575			38,966
Total common stockholder's equity		1,316,099			1,285,419
LONG-TERM DEBT (Note 8(C)):
First mortgage bonds:
6.770% due 2005		-			30,000
6.000% due 2008		-			7,830
6.100% due 2021		-			28,500
5.950% due 2027		13,690			13,690
Total first mortgage bonds		13,690			80,020
Unsecured notes:
5.720% due 2006		100,000			100,000
5.930% due 2007		50,000			50,000
4.450% due 2010		100,000			100,000
4.950% due 2013		150,000			150,000
4.875% due 2014		250,000			250,000
*   3.090% due 2021		28,500			-
Total unsecured notes		678,500			650,000
Net unamortized premium (discount) on debt		(302	)		2,151
Long-term debt due within one year		(100,000	)		(30,435	)
Total long-term debt		591,888			701,736
TOTAL CAPITALIZATION	$	1,907,987		$	1,987,155
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
* Unsecured note has a variable rate. Rate shown is the current applicable rate.

17

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
									Accumulated
				Common Stock					Other
	Comprehensive			Number		Carrying			Comprehensive			Retained
	Income			of Shares		Value			Income (Loss)			Earnings
	(Dollars in thousands)
Balance, January 1, 2003					859,500	$	1,297,784		$	(39	)	$	17,841
Net income	$	61,170											61,170
Net unrealized gain on investments		2								2
Net unrealized gain on derivative instruments		78								78
Minimum liability for unfunded retirement benefits,
net of $(23,062,000) of income taxes		(32,515	)							(32,515	)
Comprehensive income	$	28,735
Cash dividends on common stock													(52,000	)
Purchase accounting fair value adjustment							346
Balance, December 31, 2003					859,500		1,298,130			(32,474	)		27,011
Net income	$	66,955											66,955
Net unrealized loss on investments		(26	)							(26	)
Net unrealized loss on derivative instruments, net of
$(1,279,000) of income taxes		(1,819	)							(1,819	)
Minimum liability for unfunded retirement benefits,
net of $(6,502,000) of income taxes		(9,171	)							(9,171	)
Comprehensive income	$	55,939
Cash dividends on common stock													(55,000	)
Purchase accounting fair value adjustment							(8,187	)
Balance, December 31, 2004					859,500		1,289,943			(43,490	)		38,966
Net income	$	45,609											45,609
Net unrealized gain on investments,
net of $27,000 of income taxes		39								39
Net unrealized gain on derivative instruments,
net of $140,000 of income taxes		196								196
Minimum liability for unfunded retirement benefits,
net of $29,564,000 of income taxes		41,686								41,686
Comprehensive income	$	87,530
Restricted stock units							28
Cash dividends on common stock													(54,000	)
Purchase accounting fair value adjustment							(2,878	)
Balance, December 31, 2005					859,500	$	1,287,093		$	(1,569	)	$	30,575

CONSOLIDATED STATEMENTS OF PREFERRED STOCK
	Subject to
		Mandatory Redemption
		Number			Carrying
		of Shares			Value
		(Dollars in thousands)
Balance, January 1, 2003			4,000,000		$	92,409
FIN 46 Deconsolidation
7.35% Series			(4,000,000	)		(92,618	)
Amortization of fair market
value adjustment						209
Balance, December 31, 2003			-			-
Balance, December 31, 2004			-			-
Balance, December 31, 2005			-		$	-
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

18

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,	2005			2004			2003
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	45,609		$	66,955		$	61,170
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation		42,684			41,161			44,160
Amortization of regulatory assets		112,117			105,675			97,784
Deferred costs recoverable as regulatory assets		(67,763	)		(99,987	)		(102,937	)
Deferred income taxes and investment tax credits, net		(2,157	)		18,495			45,678
Accrued compensation and retirement benefits		(5,378	)		398			2,247
Cumulative effect of accounting changes (Note 2(G))		310			-			(217	)
Pension trust contribution		(35,789	)		(38,823	)		-
Decrease (increase) in operating assets:
Receivables		77,981			(65,979	)		10,380
Prepayments and other current assets		3,145			(4,457	)		2,964
Increase (decrease) in operating liabilities:
Accounts payable		(50,249	)		35,639			(20,988	)
Accrued taxes		5,954			3,195			(7,334	)
Accrued interest		(2,180	)		(230	)		(4,600	)
Other		893			11,784			4,181
Net cash provided from operating activities		125,177			73,826			132,488
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		28,500			247,606			247,696
Short-term borrowings, net		60,150			14,755			-
Redemptions and Repayments-
Long-term debt		(66,330	)		(196,371	)		(260,466	)
Short-term borrowings, net		-			-			(22,964	)
Dividend Payments-
Common stock		(54,000	)		(55,000	)		(52,000	)
Net cash provided from (used for) financing activities		(31,680	)		10,990			(87,734	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(85,627	)		(52,979	)		(43,558	)
Contributions to nuclear decommissioning trusts		(9,483	)		(9,483	)		(9,483	)
Loan repayments from (loans to) associated companies, net		1,355			(8,863	)		(7,941	)
Other		258			(13,492	)		664
Net cash used for investing activities		(93,497	)		(84,817	)		(60,318	)
Net change in cash and cash equivalents		-			(1	)		(15,564	)
Cash and cash equivalents at beginning of year		120			121			15,685
Cash and cash equivalents at end of year	$	120		$	120		$	121
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	43,266		$	43,733		$	51,505
Income taxes (refund)	$	(11,961	)	$	33,693		$	(25,085	)
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

19

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF TAXES
For the Years Ended December 31,	2005			2004			2003
	(In thousands)
GENERAL TAXES:
State gross receipts *	$	63,190		$	58,900		$	53,462
Real and personal property		1,764			1,490			2,510
Social security and unemployment		4,022			3,800			2,448
State capital stock		4,938			6,130			7,229
Other		75			137			1,558
Total general taxes	$	73,989		$	70,457		$	67,207
PROVISION FOR INCOME TAXES:
Currently payable-
Federal	$	24,191		$	12,679		$	(3,435	)
State		7,830			7,043			1,763
		32,021			19,722			(1,672	)
Deferred, net-
Federal		2,306			20,599			38,863
State		(3,637	)		(1,276	)		7,791
		(1,331	)		19,323			46,654
Investment tax credit amortization		(826	)		(828	)		(822	)
Total provision for income taxes	$	29,864		$	38,217		$	44,160
INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income	$	12,316		$	21,968		$	27,367
Other income		17,768			16,249			16,639
Cumulative effect of accounting changes		(220	)		-			154
Total provision for income taxes	$	29,864		$	38,217		$	44,160
RECONCILIATION OF FEDERAL INCOME TAX
EXPENSE AT STATUTORY RATE TO TOTAL
PROVISION FOR INCOME TAXES:
Book income before provision for income taxes	$	75,473		$	105,172		$	105,330
Federal income tax expense at statutory rate	$	26,416		$	36,810		$	36,866
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits		(826	)		(828	)		(822	)
Depreciation		2,203			2,662			1,736
State income taxes, net of federal income tax benefit		2,725			3,749			6,289
Other, net		(654	)		(4,176	)		91
Total provision for income taxes	$	29,864		$	38,217		$	44,160
ACCUMULATED DEFERRED INCOME TAXES AS OF
DECEMBER 31:
Property basis differences	$	261,171		$	250,643		$	243,571
Deferred sale and leaseback costs		(11,185	)		(11,149	)		(10,986	)
Non-utility generation costs		1,238			7,475			2,287
Purchase accounting basis difference		(642	)		(642	)		(642	)
Sale of generation assets		(1,420	)		(1,420	)		(1,420	)
Deferred nuclear expenses		(37,511	)		(32,180	)		(20,553	)
Regulatory transition charge		88,998			95,056			88,020
Asset retirement obligations		(199	)		-			-
Customer receivables for future income taxes		37,832			40,636			46,010
Other comprehensive income		(1,112	)		(30,850	)		(23,062	)
Employee benefits		9,328			(5,289	)		(17,251	)
Other		(1,569	)		(6,891	)		(8,834	)
Net deferred income tax liability	$	344,929		$	305,389		$	297,140
*  Collected from customers through regulated rates and included in revenue in the Consolidated Statements of Income.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

20

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.ORGANIZATION AND BASIS OF PRESENTATION:

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

The Company follows GAAP and complies with the regulations, orders, policies and practices prescribed by the SEC, PPUC and the FERC. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates.

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

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

2.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

(A)ACCOUNTING FOR THE EFFECTS OF REGULATION

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

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

·   are cost-based; and

·   can be charged to and collected from customers.

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

Regulatory Assets-

The Company recognizes, as regulatory assets, costs which the FERC and the PPUC have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered from customers under the Company’s regulatory plan. The Company continues to bill and collect cost-based rates for its transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Company continue the application of SFAS 71 to those operations.

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

	2005			2004
	(In millions)
Regulatory transition costs	$	308		$	692
Customer receivables for future income taxes		100			90
Nuclear decommissioning costs		(125	)		(122	)
Employee postretirement benefit costs		14			16
Loss on reacquired debt		13			15
Total	$	310		$	691

Regulatory assets for transition costs as of December 31, 2005 include deferrals associated with the Company's previously divested generation assets and incurred above-market NUG costs. These costs are being recovered through CTC revenues. The Company's NUG power purchase agreements are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for projected above-market NUG costs. Recovery of the remaining regulatory transition costs is expected to continue under the provisions of the various regulatory proceedings in Pennsylvania.

21

(B)CASH AND SHORT-TERM FINANCIAL INSTRUMENTS-

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

(C)REVENUES AND RECEIVABLES-

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

Receivables from customers include sales to residential, commercial and industrial customers and sales to wholesale customers. There was no material concentration of receivables as of December 31, 2005, with respect to any particular segment of the Company's customers. Total customer receivables were $130 million (billed - $78 million and unbilled - $52 million) and $120 million (billed - $74 million and unbilled - $46 million) as of December 31, 2005 and 2004, respectively.

(D)PROPERTY, PLANT AND EQUIPMENT-

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

The Company provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annualized composite rate was approximately 2.4% in 2005 and 2004 and 2.6% in 2003. The decrease in the composite depreciation rate reflects changes in the depreciable plant base due to assets with higher depreciation rates being fully depreciated since 2002.

(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 annual review was completed in the third quarter of 2005 with no impairment indicated. The forecasts used in the Company's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on the Company's future evaluations of goodwill. As of December 31, 2005, the Company had $864 million of goodwill. In 2005, the Company adjusted goodwill for the reversal of tax valuation allowances related to income tax benefits realized attributable to prior period capital loss carryforwards that were used to offset capital gains generated in 2005 and above-market NUGs.

22

Investments

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

(F)COMPREHENSIVE INCOME-

Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholder’s equity except those resulting from transactions with FirstEnergy. As of December 31, 2005 accumulated other comprehensive loss consisted of unrealized losses on derivative instrument hedges of $2 million. As of December 31, 2004 accumulated other comprehensive loss consisted of a minimum liability for unfunded retirement benefits of $42 million and unrealized losses on derivative instrument hedges of $2 million.

(G)CUMULATIVE EFFECT OF ACCOUNTING CHANGE

Results in 2005 include an after-tax charge of $0.3 million recorded upon the adoption of FIN 47 in December 2005. The Company identified applicable legal obligations as defined under the new standard at its substation control rooms, service center buildings, line shops and office buildings, identifying asbestos as the primary conditional ARO. The Company recorded a conditional ARO liability of $0.6 million (including accumulated accretion for the period from the date the liability was incurred to the date of adoption), an asset retirement cost of $0.2 million (recorded as part of the carrying amount of the related long-lived asset) and accumulated depreciation of $0.1 million.

As a result of adopting SFAS 143 in January 2003, asset retirement costs were recorded in the amount of $186 million as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $186 million. The ARO liability on the date of adoption was $198 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. The remaining cumulative effect adjustment for unrecognized depreciation and accretion, offset by the reduction in the existing decommissioning liabilities and the reversal of accumulated estimated removal costs for non-regulated generation assets, was a $0.4 million increase to income ($0.2 million, net of tax) in the year ended December 31, 2003.

(H)INCOME TAXES-

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

(I)TRANSACTIONS WITH AFFILIATED COMPANIES-

Operating expenses and other income included transactions with affiliated companies, primarily FESC, GPUS and FES. GPUS (until it ceased operations in mid-2003) and FESC have provided legal, accounting, financial and other corporate support services to the Company. The Company purchases a portion of its PLR responsibility from FES through a wholesale power sale agreement. The primary affiliated companies' transactions are as follows:

	2005		2004		2003
	(In millions)
Services Received:
Power purchased from FES	$	348	$	434	$	277
Service Company support services		45		46		50
Power purchased from other affiliates		-		-		2

23

FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Company from FESC, which is a subsidiary of FirstEnergy. The vast majority of costs are directly billed or assigned at no more than cost. 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 developed by FESC. 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.

3.   PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS:

FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees. The trusteed plans provide defined benefits based on years of service and compensation levels. The Company's funding policy is based on actuarial computations using the projected unit credit method. In the fourth quarter of 2005, FirstEnergy made a $500 million voluntary cash contribution to its pension plan (the Company's share was $36 million). Projections indicated that absent this funding, cash contributions would have been required at some point prior to 2010. Pre-funding the pension plan is expected to eliminate this future funding requirement under current pension funding rules and should also minimize FirstEnergy's exposure to any funding requirements resulting from proposed pension reform.

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 co-payments, are also available upon retirement to employees hired prior to January 1, 2005, 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. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement for disability related 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 most of its plans.

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

Obligations and Funded Status	Pension Benefits						Other Benefits
As of December 31	2005			2004			2005			2004
	(In millions)
Change in benefit obligation
Benefit obligation as of January 1	$	4,364		$	4,162		$	1,930		$	2,368
Service cost		77			77			40			36
Interest cost		254			252			111			112
Plan participants’ contributions		-			-			18			14
Plan amendments		15			-			(312	)		(281	)
Actuarial (gain) loss		310			134			197			(211	)
Benefits paid		(270	)		(261	)		(100	)		(108	)
Benefit obligation as of December 31	$	4,750		$	4,364		$	1,884		$	1,930
Change in fair value of plan assets
Fair value of plan assets as of January 1	$	3,969		$	3,315		$	564		$	537
Actual return on plan assets		325			415			33			57
Company contribution		500			500			58			64
Plan participants’ contribution		-			-			18			14
Benefits paid		(270	)		(261	)		(100	)		(108	)
Fair value of plan assets as of December 31	$	4,524		$	3,969		$	573		$	564
Funded status	$	(226	)	$	(395	)	$	(1,311	)	$	(1,366	)
Unrecognized net actuarial loss		1,179			885			899			730
Unrecognized prior service cost (benefit)		70			63			(645	)		(378	)
Net asset (liability) recognized	$	1,023		$	553		$	(1,057	)	$	(1,014	)

24

Amounts Recognized in the Consolidated Balance Sheets As of December 31
Prepaid benefit cost	$	1,023		$	-		$	-		$	-
Accrued benefit cost		-			(14	)		(1,057	)		(1,014	)
Intangible assets		-			63			-			-
Accumulated other comprehensive loss		-			504			-			-
Net amount recognized	$	1,023		$	553		$	(1,057	)	$	(1,014	)
Company's share of net amount recognized	$	89		$	49		$	(57	)	$	(59	)
Decrease in minimum liability included in other comprehensive income(net of tax)	$	(295	)	$	(4	)	$	-		$	-
Assumptions Used to Determine Benefit Obligations As of December 31
Discount rate		5.75	%		6.00	%		5.75	%		6.00	%
Rate of compensation increase		3.50	%		3.50	%
Allocation of Plan Assets As of December 31 Asset Category
Equity securities		63	%		68	%		71	%		74	%
Debt securities		33			29			27			25
Real estate		2			2			-			-
Cash		2			1			2			1
Total		100	%		100	%		100	%		100	%

Information for Pension Plans With an
Accumulated Benefit Obligation in
Excess of Plan Assets	2005		2004
	(In millions)
Projected benefit obligation	$	4,750	$	4,364
Accumulated benefit obligation		4,327		3,983
Fair value of plan assets		4,524		3,969

	Pension Benefits									Other Benefits
Components of Net Periodic Benefit Costs	2005			2004			2003			2005			2004			2003
	(In millions)
Service cost	$	77		$	77		$	66		$	40		$	36		$	43
Interest cost		254			252			253			111			112			137
Expected return on plan assets		(345	)		(286	)		(248	)		(45	)		(44	)		(43	)
Amortization of prior service cost		8			9			9			(45	)		(40	)		(9	)
Amortization of transition obligation		-			-			-			-			-			9
Recognized net actuarial loss		36			39			62			40			39			40
Net periodic cost	$	30		$	91		$	142		$	101		$	103		$	177
Company's share of net periodic cost (income)	$	(4	)	$	-		$	5		$	2		$	3		$	7

Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost
	Pension Benefits						Other Benefits
for Years Ended December 31	2005		2004		2003		2005		2004		2003
Discount rate	6.00	%	6.25	%	6.75	%	6.00	%	6.25	%	6.75	%
Expected long-term return on plan assets	9.00	%	9.00	%	9.00	%	9.00	%	9.00	%	9.00	%
Rate of compensation increase	3.50	%	3.50	%	3.50	%

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 rates of return on pension plan assets consider 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.

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FirstEnergy employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return on 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 capitalization funds. 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	2005			2004
Health care cost trend rate assumed for next year (pre/post-Medicare)	9-11		%	9-11		%
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)		2010-2012			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 ncrease		Point Decrease
	(In millions)
Effect on total of service and interest cost	$	23	$	(19	)
Effect on postretirement benefit obligation	$	239	$	(209	)

As a result of its voluntary contribution and the increased market value of pension plan assets, the Company recognized a prepaid benefit cost of $89 million as of December 31, 2005. As prescribed by SFAS 87, the Company eliminated its additional minimum liability of $71 million. In addition, the entire AOCL balance was credited by $42 million (net of $29 million of deferred taxes) as the fair value of trust assets exceeded the accumulated benefit obligation as of December 31, 2005.

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

	Pension Benefits		Other Benefits
	(In millions)
2006	$	228	$	106
2007		228		109
2008		236		112
2009		247		115
2010		264		119
Years 2011- 2015		1,531		642

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:

	2005				2004
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Long-term debt	$	692	$	683	$	730	$	731

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:

	2005				2004
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Debt securities:(1)
-Government obligations	$	87	$	87	$	78	$	78
-Corporate debt securities		6		6		5		5
		93		93		83		83
Equity securities(1)		142		142		137		137
	$	235	$	235	$	220	$	220

⁽¹⁾Includes nuclear decommissioning trust investments.

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

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

	2005								2004
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
	(In millions)
Debt securities	$	92	$	2	$	1	$	93	$	80	$	3	$	-	$	83
Equity securities		113		30		1		142		113		24		3		134
	$	205	$	32	$	2	$	235	$	193	$	27	$	3	$	217

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, 2005 were as follows:

	2005		2004		2003
	(In millions)
Proceeds from sales	$	138	$	179	$	84
Gross realized gains		6		30		2
Gross realized losses		7		1		1
Interest and dividend income		6		6		5

The following table provides the fair value and gross unrealized losses of nuclear decommissioning trust investments that are deemed to be temporarily impaired as of December 31, 2005:

	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	$	29	$	-	$	10	$	-	$	39	$	1
Equity securities		20		1		4		1		24		1
	$	49	$	1	$	14	$	1	$	63	$	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 recovery of amounts contributed to the Company's decommissioning trusts are subject to regulatory accounting in accordance with SFAS 71. Net unrealized gains and losses are recorded as regulatory liabilities or assets since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers.

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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 the regulatory treatment, the rentals for operating leases are charged to operating expenses on the Consolidated Statements of Income. The Company's most significant operating leases relate to the sale and leaseback of a portion of its ownership interest in the Merrill Creek Reservoir project and the lease of vehicles.

Such costs for the three years ended December 31, 2005 are summarized as follows:

	2005		2004		2003
	(In millions)
Operating leases
Interest element	$	1.9	$	1.8	$	1.9
Other		1.0		1.1		1.6
Total rentals	$	2.9	$	2.9	$	3.5

The future minimum lease payments as of December 31, 2005 are:

	Operating Leases
	(In millions)
2006	$	3.5
2007		3.4
2008		3.3
2009		3.5
2010		3.3
Years thereafter		46.0
Total minimum lease payments		63.0

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 entity’s 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 Company consolidates VIEs when it is determined to be the VIE’s primary beneficiary as defined by FIN 46R.

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

The Company has determined that for all but one of these entities, the Company has no variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of FIN 46R. The Company may hold a variable interest in the remaining entity, which sells its output at variable price that correlates to some extent with the operating costs of the plant. As required by FIN 46R, the Company periodically requests the information necessary from this entity to determine whether it is a VIE or whether the Company is the primary beneficiary. The Company has been unable to obtain the requested information, which was deemed by the requested entity to be proprietary. As such, the Company applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R. The purchased power costs from this entity during 2005, 2004 and 2003 were $50 million, $54 million and $53 million, respectively.

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7.  REGULATORY MATTERS:

In late 2003 and early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task Force) regarding enhancements to regional reliability. In 2004, FirstEnergy completed implementation of all actions and initiatives related to enhancing area reliability, improving voltage and reactive management, operator readiness and training and emergency response preparedness recommended for completion in 2004. On July 14, 2004, NERC independently verified that FirstEnergy had implemented the various initiatives to be completed by June 30 or summer 2004, with minor exceptions noted by FirstEnergy, which exceptions are now essentially complete. FirstEnergy is proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future as the result of adoption of mandatory reliability standards pursuant to the EPACT 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.

The EPACT provides for the creation of an ERO to establish and enforce reliability standards for the bulk power system, subject to FERC review. On February 3, 2006, the FERC adopted a rule establishing certification requirements for the ERO, as well as regional entities envisioned to assume monitoring responsibility for the new reliability standards.

The NERC has been preparing the implementation aspects of reorganizing its structure to meet the FERC’s certification requirements for the ERO. The NERC will make a filing with the FERC to obtain certification as the ERO and to obtain FERC approval of delegation agreements with regional entities. The new FERC rule referred to above, further provides for reorganizing regional reliability organizations (regional entities) that would replace the current regional councils and for rearranging the relationship with the ERO. The “regional entity” may be delegated authority by the ERO, subject to FERC approval, for enforcing reliability standards adopted by the ERO and approved by the FERC. NERC also intends to make a parallel filing with the FERC seeking approval of mandatory reliability standards. These reliability standards are expected to be based on the current NERC Version 0 reliability standards with some additional standards. The two filings are expected to be made in the second quarter of 2006.

The ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils have completed the consolidation of these regions into a single new regional reliability organization known as ReliabilityFirst Corporation. ReliabilityFirst began operations as a regional reliability council under NERC on January 1, 2006 and intends to file and obtain certification consistent with the final rule as a “regional entity” under the ERO during 2006. All of FirstEnergy’s facilities are located within the ReliabilityFirst region.

   On a parallel path, the NERC is establishing working groups to develop reliability standards to be filed for approval with the FERC following the NERC’s certification as an ERO. These reliability standards are expected to build on the current NERC Version 0 reliability standards. It is expected that the proposed reliability standards will be filed with the FERC in early 2006.

FirstEnergy believes it is in compliance with all current NERC reliability standards. However, it is expected that the FERC will adopt stricter reliability standards than those contained in the current NERC Version 0 standards. The financial impact of complying with the new standards cannot be determined at this time. However, the EPACT required that all prudent costs incurred to comply with the new reliability standards be recovered in rates.

In May 2004, the PPUC issued an order approving revised reliability benchmarks and standards, including revised benchmarks and standards for the Company. The Company filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004, due to their implementation of automated outage management systems following restructuring. On December 30, 2005, the ALJ recommended that the PPUC adopt the Joint Petition for Settlement among the parties involved in the Company's request to amend the distribution reliability benchmarks, thereby eliminating the need for full litigation. The ALJ’s recommendation, adopting the revised benchmarks and standards was approved by the PPUC on February 9, 2006.

A February 2002 Commonwealth Court of Pennsylvania decision affirmed the June 2001 PPUC decision regarding approval of the FirstEnergy/GPU merger, remanded the issues of quantification and allocation of merger savings to the PPUC and denied the Company the rate relief initially approved in the PPUC decision. On October 2, 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC’s June 2001 order in its entirety. In accordance with the PPUC's direction, the Company filed supplements to its tariffs that became effective in October 2003 and that reflected the CTC rates and shopping credits in effect prior to the June 2001 order.

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The Company and Penelec had been negotiating with interested parties in an attempt to resolve the merger savings issues that are the subject of remand from the Commonwealth Court. The Company's and Penelec’s combined portion of total merger savings during 2001 - 2004 is estimated to be approximately $51 million. In late 2005, settlement discussions broke off as unsuccessful. A procedural schedule was established by the ALJ on January 17, 2006. The companies’ initial testimony is due on March 1, 2006 with testimony of the other parties and additional testimony by the companies to be filed through October, 2006. Hearings are scheduled for the end of October 2006 with the ALJ’s recommended decision to be issued in February, 2007. The companies are unable to predict the outcome of this proceeding.

In an October 16, 2003 order, the PPUC approved September 30, 2004 as the date for the Company's NUG trust fund refunds. The PPUC order also denied its accounting treatment request regarding the CTC rate/shopping credit swap by requiring the Company to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. On October 22, 2003, the Company filed an Objection with the Commonwealth Court asking that the Court reverse this PPUC finding; a Commonwealth Court judge subsequently denied its Objection on October 27, 2003 without explanation. On October 31, 2003, the Company filed an Application for Clarification of the Court order with the judge, a Petition for Review of the PPUC's October 2 and October 16, 2003 Orders, and an application for reargument, if the judge, in his clarification order, indicates that the Company's Objection was intended to be denied on the merits. The Reargument Brief before the Commonwealth Court was filed on January 28, 2005.

As of December 31, 2005, the Company's regulatory deferral pursuant to the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation is $333 million.

 Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sales agreement and a portion from contracts with unaffiliated third party suppliers, including NUGs. Assuming continuation of these existing contractual arrangements, the available supply represents approximately 100% of the combined retail sales obligations of Met-Ed and Penelec in 2006 and 2007; almost 100% for 2008; and approximately 85% for 2009 and 2010. Met-Ed and Penelec are authorized to defer any excess of NUG contract costs over current market prices. Under the terms of the wholesale agreement with FES, FES retains the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their contracts with NUGs and other unaffiliated suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR energy costs during the term of the agreement with FES. The wholesale agreement with FES is automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. On November 1, 2005, FES and the other parties thereto amended the agreement to provide FES the right over the next year to terminate the agreement at any time upon 60 days notice. If the wholesale power agreement were terminated or modified, Met-Ed and Penelec would need to satisfy the portion of their PLR obligations currently supplied by FES from unaffiliated suppliers at prevailing prices, which are likely to be higher than the current price charged by FES under the agreement and, as a result, Met-Ed’s and Penelec’s purchased power costs could materially increase. If Met-Ed and Penelec were to replace the FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer support an investment grade rating for its fixed income securities. Met-Ed and Penelec are in the process of preparing a comprehensive rate filing that will address a number of transmission, distribution and supply issues and is expected to be filed with the PPUC in the second quarter of 2006. That filing will include, among other things, a request for appropriate regulatory action to mitigate adverse consequences from any future reduction, in whole or in part, in the availability to Met-Ed and Penelec of supply under the existing FES agreement. There can be no assurance, however, that if FES ultimately determines to terminate, or significantly modify the agreement, timely regulatory relief will be granted by the PPUC or, to the extent granted, adequate to mitigate such adverse consequences.

The Company, ATSI, JCP&L, Penelec, and FES continue to be involved in FERC hearings concerning the calculation and imposition of Seams Elimination Cost Adjustment (SECA) charges to various load serving entities. Pursuant to its January 30, 2006 Order, the FERC has compressed both phases of this proceeding into a single hearing scheduled to begin May 1, 2006, with an initial decision on or before August 11, 2006.

   On January 12, 2005, the Company filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005, estimated to be approximately $4 million per month. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association have all intervened in the case. To date, no hearing schedule has been established, and the Company has not yet implemented deferral accounting for these costs.

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On January 31, 2005, certain PJM transmission owners made three filings pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On June 30, 2005, the PJM transmission owners filed a request for rehearing of the May 31, 2005 order. The rate design and formula rate proceedings are currently being litigated before the FERC. If FERC accepts AEP’s proposal to create a “postage stamp” rate for high voltage transmission facilities across PJM, significant additional transmission revenues would be imposed on JCP&L, Met-Ed, Penelec, and other transmission zones within PJM.

8.CAPITALIZATION:

(A)RETAINED EARNINGS-

In general, the Company’s first mortgage 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, 2005, the Company had retained earnings available to pay common stock dividends of $27 million, net of amounts restricted under the Company’s first mortgage indenture.

(B)PREFERRED AND PREFERENCE STOCK-

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

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

The Company’s first mortgage indenture, which secures all of the Company’s FMB, 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, 2005, the Company’s annual sinking fund requirements for all bonds issued under the mortgage amount to $8 million. The Company could fulfill its sinking fund obligation by providing refundable bonds, property additions or cash to the Trustee.

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

	(In millions)
2006	$	100
2007		50
2008		-
2009		-
2010		100

The Company’s obligations to repay certain pollution control revenue bonds are secured by several series of FMB. Certain pollution control revenue bonds are entitled to the benefit of noncancelable municipal bond insurance policies of $42 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the policies, the Company is entitled to a credit against its obligation to repay that bond. For the pollution control revenue bonds issued in 2005, the Company pays annual fees of 0.16% of the amount of the policy to the insurer. The Company is obligated to reimburse the insurers for any drawings thereunder.

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9. ASSET RETIREMENT OBLIGATIONS

In January 2003, the Company implemented SFAS 143, which provides accounting guidance for retirement obligations associated with tangible long-lived assets. This standard requires recognition of the fair value of a liability for an ARO in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the ARO increases, resulting in a period expense. 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 initially identified applicable legal obligations as defined under the standard for nuclear power plant decommissioning of TMI-2. The ARO liability as of the date of adoption was $198 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. The Company expects substantially all nuclear decommissioning costs to be recoverable through regulated rates.Therefore, a regulatory liability of $61 million was recognized upon adoption of SFAS 143. The Company’s share of the obligation to decommission these units was developed based on site specific studies performed by an independent engineer. The Company utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.

In 2004, the Company revised the ARO associated with TMI-2 as the result of an updated 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 TMI-2 ARO liability and corresponding regulatory asset was $89 million.

The Company maintains the nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of December 31, 2005, the fair value of the decommissioning trust assets was $235 million.

The Company implemented FIN 47, "Accounting for Conditional Asset Retirement Obligations", an interpretation of SFAS 143 on December 31, 2005. FIN 47 provides accounting standards for conditional retirement obligations associated with tangible long-lived assets, requiring recognition of the fair value of a liability for an ARO in the period in which it is incurred if a reasonable estimate can be identified. FIN 47 states that anobligation exists even though there may be uncertainty about timing or method of settlement andfurther clarifies SFAS 143, stating that the uncertainty surrounding the timing and method of settlement when settlement is conditional on a future event occurring should be reflected in the measurement of the liability not in the recognition of the liability. Accounting fro conditional ARO under FIN 47 is the same as described above for SFAS 143.

The Company identified applicable legal obligations as defined under the new standard at its hydroelectric generation facilities, substation control rooms, service center buildings, line shops and office buildings, identifying asbestos as the primary conditional ARO. As a result of adopting FIN 47 in December 2005, the Company recorded a conditional ARO liability of $0.6 million (including accumulated accretion for the period from the date the liability was incurred to the date of adoption), an asset retirement cost of $0.2 million (recorded as part of the carrying amount of the related long-lived asset) and accumulated depreciation of $0.1 million. As a result, the Company recorded a $0.5 million cumulative effect adjustment ($0.3 million, net of tax) for unrecognized depreciation and accretion as of December 31, 2005. The costs of remediation were based on costs incurred during recent remediation projects performed at each of these locations. The conditional ARO liability was developed utilizing an expected cash flow approach (as discussed in SFAC 7) to measure the fair value of the ARO. The Company used a probability weighted analysis to estimate when remediation payments would begin. The effect on income as if FIN 47 had been applied during 2004 and 2003 was immaterial.

The following table describes the changes to the ARO balances during 2005 and 2004:

	2005		2004
ARO Reconciliation	(In millions)
Balance at beginning of year	$	133	$	210
Accretion		8		12
Revisions in estimated cash flows		-		(89	)
FIN 47 ARO		1		-
Balance at end of year	$	142	$	133

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10.SHORT-TERM BORROWINGS:

Short-term borrowings outstanding as of December 31, 2005, consisted of $140 million of borrowings from affiliates. Met-Ed Funding, a wholly owned subsidiary of Met-Ed, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Met-Ed. It can borrow up to $80 million under a receivables financing arrangement at rates based on certain bank commercial paper and is required to pay an annual facility fee is 0.15% on the entire finance limit. This financing arrangement expires on June 29, 2006. As a separate legal entity with separate creditors, it would have to satisfy its obligations to creditors before any of its remaining assets could be made available to the Company.

In June 2005, the Company, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Penelec, FES and ATSI, as Borrowers, entered into a syndicated $2 billion five-year revolving credit facility with a syndicate of banks that expires in June 2010. Borrowings under the facility are available to each Borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment expiration date, as the same may be extended. The Company's borrowing limit under the facility is $250 million. The average interest rate on short-term borrowings outstanding as of December 31, 2005 and 2004, was 4.0% and 2.0%, respectively.

11.    COMMITMENTS, GUARANTEES AND CONTINGENCIES:

   (A)NUCLEAR INSURANCE-

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

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

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

 (B)ENVIRONMENTAL MATTERS-

The Company accrues environmental liabilities only when it concludes that it is probable that we have an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in our determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

The Company has been named as a PRP at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of December 31, 2005, based on estimates of the total costs of cleanup, the Company’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $49,000 have been accrued through December 31, 2005.

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(C)OTHER LEGAL PROCEEDINGS-

Power Outages and Related Litigation

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, 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 contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of December 31, 2005 for any expenditures in excess of those actually incurred through that date. The FERC or other applicable government agencies and reliability coordinators may, however, 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 FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators before determining the next steps, if any, in the proceeding.

In addition to the above proceedings, FirstEnergy was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter has been filed. FirstEnergy was also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy are based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. No FirstEnergy entity serves any customers in Jersey City. A responsive pleading has been filed. No estimate of potential liability has been undertaken in either of these matters.

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

Legal Matters

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

12. `NEW ACCOUNTING STANDARDS AND INTERPRETATIONS:

FSP FAS 115-1 and FAS 124-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

Issued in November 2005, FSP 115-1 and FAS 124-1 addresses the determination as to when an investment is considered impaired, whether that impairment is other than temporary, and the measurement of an impairment loss. The FSP finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. This FSP will (1) nullify certain requirements of Issue 03-1 and supersedes EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when the impairment is deemed other than temporary, even if a decision to sell has not been made, and (3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after September 15, 2005. The FSP requires prospective application with an effective date for reporting periods beginning after December 15, 2005. The Company is currently evaluating this FSP and any impact on its investments.

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EITF Issue 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"

In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, the Company will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006.

SFAS 154 - “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in the Consolidated Statements of Income. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company adopted this Statement effective January 1, 2006.

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

In December 2004, the FASB issued SFAS 153 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 January 1, 2006 for the Company. This FSP is not expected to have a material impact on the Company’s financial statements.

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

In November 2004, the FASB issued SFAS 151 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 beginning January 1, 2006. The Company does not expect this statement to have a material impact on its financial statements.

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13.SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):

The following summarizes certain consolidated operating results by quarter for 2005 and 2004.

	March 31,		June 30,		Sept. 30,		Dec. 31,
Three Months Ended	2005		2005		2005		2005
	(In millions)
Operating Revenues	$	295.8	$	263.1	$	333.2	$	284.3
Operating Expenses and Taxes		274.7		243.1		327.9		267.6
Operating Income		21.1		20.0		5.3		16.7
Other Income		6.4		7.0		6.5		7.2
Net Interest Charges		11.0		11.3		10.8		11.2
Income before cumulative effect		16.5		15.7		1.0		12.7
Cumulative effect of accounting change		-		-		-		(0.3	)
Net Income	$	16.5	$	15.7	$	1.0	$	12.4

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

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