FirstEnergy (FE) 10-K 2005 FY Annual report

OHIO EDISON COMPANY

2005 ANNUAL REPORT TO STOCKHOLDERS

Ohio Edison Company is a wholly owned electric utility operating subsidiary of FirstEnergy Corp. Ohio Edison engages in the distribution and sale of electric energy to communities in an area of 7,500 square miles in central and northeastern Ohio and, through its wholly owned Pennsylvania Power Company subsidiary, 1,500 square miles in western Pennsylvania. It also engages in the sale, purchase and interchange of electric energy with other electric companies. The areas Ohio Edison and Pennsylvania Power serve have populations of approximately 2.8 million and 0.3 million, respectively.

Contents	Page
Glossary of Terms	i-ii
Report of Independent Registered Public Accounting Firm	1
Selected Financial Data	2
Management's Discussion and Analysis	3-19
Consolidated Statements of Income	20
Consolidated Balance Sheets	21
Consolidated Statements of Capitalization	22-23
Consolidated Statements of Common Stockholder's Equity	24
Consolidated Statements of Preferred Stock	24
Consolidated Statements of Cash Flows	25
Consolidated Statements of Taxes	26
Notes to Consolidated Financial Statements	27-48

GLOSSARY OF TERMS

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

ATSI	American Transmission Systems, Inc., owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an affiliated Ohio electric utility
Companies	OE and Penn
FENOC	FirstEnergy Nuclear Operating Company, operates nuclear generating facilities
FES	FirstEnergy Solutions Corp., provides energy-related products and services
FESC	FirstEnergy Service Company, provides legal, financial, and other corporate support services
FGCO	FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities
FirstEnergy	FirstEnergy Corp., a public utility holding company
JCP&L	Jersey Central Power & Light Company, an affiliated New Jersey electric utility
Met-Ed	Metropolitan Edison Company, an affiliated Pennsylvania electric utility
NGC	FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities
OE	Ohio Edison Company
Ohio Companies	CEI, OE and TE
Penelec	Pennsylvania Electric Company, an affiliated Pennsylvania electric utility
Penn	Pennsylvania Power Company, OE's wholly owned Pennsylvania electric utility subsidiary
PNBV	PNBV Capital Trust, a special purpose entity created by OE in 1996
TE	The Toledo Edison Company, an affiliated Ohio electric utility
The following abbreviations and acronyms are used to identify frequently used terms in this report:
ALJ	Administrative Law Judge
AOCL	Accumulated Other Comprehensive Loss
APB	Accounting Principles Board
APB 29	APB Opinion No. 29, "Accounting for Nonmonetary Transactions"
ARB	Accounting Research Bulletin
ARB 43	ARB No. 43, "Restatement and Revision of Accounting Research Bulletins"
ARO	Asset Retirement Obligation
CAL	Confirmatory Action Letter
CAT	Commercial Activity Tax
CO2	Carbon Dioxide
CTC	Competitive Transition Charge
DOJ	United States Department of Justice
ECAR	East Central Area Reliability Coordination Agreement
EITF	Emerging Issues Task Force
EITF 03-1	EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its Application to Certain Investments”
EITF 04-13	EITF Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"
EPA	Environmental Protection Agency
EPACT	Energy Policy Act of 2005
ERO	Energy Reliability Organization
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, Improvement 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
GCAF	Generation Charge Adjustment Factor

i

IRS	Internal Revenue Service
KWH	Kilowatt-hours
LOC	Letter of Credit
Medicare Act	Medicare Prescription Drug, Improvement and Modernization Act of 2003
MISO	Midwest Independent System Transmission Operator, Inc.
Moody’s	Moody’s Investors Service
MSG	Market Support Generation
MW	Megawatts
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Council
NOAC	Northwest Ohio Aggregation Coalition
NOV	Notices of Violation
NOX	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
OCC	Office of the Ohio Consumers' Counsel
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
PJM	PJM Interconnection L.L.C.
PLR	Provider of Last Resort
PPUC	Pennsylvania Public Utility Commission
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act
RCP	Rate Certainty Plan
RSP	Rate Stabilization Plan
RFP	Request for Proposal
RTC	Regulatory Transition Charge
S&P	Standard & Poor’s Ratings Service
SEC	U.S. 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 101	SFAS No. 101, "Accounting for Discontinuation of Application of SFAS 71"
SFAS 106	SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions"
SFAS 115	SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities"
SFAS 143	SFAS No. 143, "Accounting for Asset Retirement Obligations"
SFAS 144	SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"
SFAS 150	SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity"
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"
SO2	Sulfur Dioxide
VIE	Variable Interest Entity

ii

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Ohio 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 Ohio 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 11 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.

OHIO EDISON COMPANY
SELECTED FINANCIAL DATA
	2005			2004			2003			2002			2001
	(Dollars in thousands)
GENERAL FINANCIAL INFORMATION:
Operating Revenues	$	2,975,553		$	2,945,583		$	2,925,310		$	2,948,675		$	3,056,464
Operating Income	$	335,383		$	335,529		$	336,936		$	453,831		$	466,819
Income Before Cumulative Effect
of Accounting Changes	$	330,398		$	342,766		$	292,925		$	356,159		$	350,212
Net Income	$	314,055		$	342,766		$	324,645		$	356,159		$	350,212
Earnings on Common Stock	$	311,420		$	340,264		$	321,913		$	349,649		$	339,510
Total Assets	$	6,097,277		$	6,482,627		$	7,316,489		$	7,789,539		$	7,915,391
CAPITALIZATION AS OF DECEMBER 31:
Common Stockholder’s Equity	$	2,502,191		$	2,493,809		$	2,582,970		$	2,839,255		$	2,671,001
Preferred Stock-
Not Subject to Mandatory Redemption		75,070			100,070			100,070			100,070			200,070
Subject to Mandatory Redemption		-			-			-			13,500			134,250
Long-Term Debt and Other Long-Term Obligations		1,019,642			1,114,914			1,179,789			1,219,347			1,614,996
Total Capitalization	$	3,596,903		$	3,708,793		$	3,862,829		$	4,172,172		$	4,620,317
CAPITALIZATION RATIOS:
Common Stockholder’s Equity		69.6	%		67.2	%		66.9	%		68.1	%		57.8	%
Preferred Stock-
Not Subject to Mandatory Redemption		2.1			2.7			2.6			2.4			4.3
Subject to Mandatory Redemption		-			-			-			0.3			2.9
Long-Term Debt and Other Long-Term Obligations		28.3			30.1			30.5			29.2			35.0
Total Capitalization		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%
DISTRIBUTION KWH DELIVERIES (Millions):
Residential		10,901			10,180			10,009			10,233			9,646
Commercial		8,566			8,276			8,105			7,994			7,967
Industrial		11,058			10,700			10,658			10,672			10,995
Other		154			144			160			154			152
Total		30,679			29,300			28,932			29,053			28,760
CUSTOMERS SERVED:
Residential		1,062,665			1,056,560			1,044,419			1,041,825			1,033,414
Commercial		130,472			129,017			127,856			119,771			118,469
Industrial		1,152			1,149			1,182			4,500			4,573
Other		1,890			1,751			1,752			1,756			1,664
Total		1,196,179			1,188,477			1,175,209			1,167,852			1,158,120
Number of Employees		1,422			1,370			1,521			1,569			1,618

2

OHIO 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, the Public Utilities Commission of Ohio and the Pennsylvania Public Utility Commission as disclosed in our Securities and Exchange Commission filings, generally, and with respect to heightened scrutiny at the Perry Nuclear Power Plant in particular, 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.

FirstEnergy Intra-System Generation Asset Transfers

On May 13, 2005, Penn, and on May 18, 2005, the Ohio Companies entered into certain agreements implementing a series of intra-system generation asset transfers that were completed in the fourth quarter of 2005. The asset transfers resulted in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC, and FGCO, respectively. The generating plant interests transferred do not include our leasehold interests in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.

On October 24, 2005, we completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to FGCO's purchase option under the Master Facility Lease.

On December 16, 2005, we completed the intra-system transfer of our ownership interests in the nuclear generation assets to NGC through an asset spin-off in the form of a dividend. FENOC continues to operate and maintain the nuclear generation assets.

These transactions were undertaken pursuant to the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. The transactions essentially completed the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants.

3

The transfers are expected to affect our near-term future results with reductions in revenues and expenses. Revenues will be reduced due to the termination of the sale of our nuclear-generated KWH and the lease of our non-nuclear-generated assets arrangements with FES. Our expenses will be lower due to the nuclear fuel and operating costs assumed by NGC as well as depreciation and property tax expenses assumed by FGCO and NGC related to the transferred generating assets. OE will retain the nuclear-generated KWH sales arrangement and the portion of expenses related to our retained leasehold interests in Perry and Beaver Valley Unit 2. In addition, we will receive interest income from associated company notes receivable from FGCO and NGC for the transfer of our generation net assets and eliminate the interest expense on certain pollution control notes to be transferred to FGCO and NGC. FES will continue to provide our PLR requirements under revised purchased power arrangements for a three-year period beginning January 1, 2006 (see Regulatory Matters).

Results of Operations

  Earnings on common stock in 2005 decreased to $311 million from $340 million in 2004. Earnings on common stock in 2005 included an after-tax charge to income of $16 million from the cumulative effect of an accounting change due to the adoption of FIN 47 in December 2005 (see Note 2(G)). Income before the cumulative effect of an accounting change was $330 million in 2005. The earnings decrease in 2005 primarily resulted from increases in regulatory asset amortization and other operating costs and a decrease in other income, partially offset by higher operating revenues and lower purchased power and nuclear operating costs compared to 2004.

  Earnings on common stock in 2004 increased to $340 million from $322 million in 2003. Earnings on common stock in 2003 included an after-tax gain of $32 million from the cumulative effect of an accounting change due to the adoption of SFAS 143 (see Note 2(G)). Income before the cumulative effect of an accounting change was $293 million in 2003. The earnings increase in 2004 primarily resulted from lower nuclear operating costs and reduced financing costs, partially offset by higher purchased power costs compared to 2003.

Operating Revenues

Operating revenues increased by $30 million (1.0%) in 2005 compared with 2004 primarily due to increases of $50 million in retail generation and $43 million in distribution deliveries, partially offset by decreases of $37 million in wholesale sales revenue, $32 million in lease revenues from associated companies and an additional $6 million in shopping incentive credits discussed below. Increased retail generation revenues (residential - $20 million; commercial - $9 million; and industrial - $22 million) reflected the impact of higher KWH sales. The increased generation KWH sales to residential (7.0%) and commercial (4.5%) customers were due to warmer summer weather in 2005, compared to 2004, which increased air-conditioning loads. Increased industrial revenues were primarily due to higher unit prices and also reflected the impact of a 1.9% increase in generation KWH sales. Industrial sales were affected by increased shopping as generation services provided to industrial customers by alternative suppliers as a percent of total industrial sales delivered in our service area increased by 1.0 percentage point. Commercial customer shopping decreased slightly by 0.6 percentage point and residential customer shopping remained relatively unchanged compared to 2004.

The intra-system generation asset transfers discussed above had an effect on our wholesale sales revenues and lease revenues in the fourth quarter of 2005. Lower wholesale revenues in 2005 compared to 2004 reflected decreased sales to FES of $61 million (8.1% KWH sales decrease), due to reduced nuclear generation available for sale. In addition, the nuclear asset transfers on December 16, 2005 terminated our nuclear generation sales arrangement with FES (except for those revenues related to our retained nuclear leasehold interests). The decreased sales to FES were partially offset by a $24 million increase in sales to unaffiliated customers (including MSG sales) reflecting increased KWH sales (2.7%) and higher unit prices. Revenues from the leases of fossil generation assets to FGCO decreased when the lease arrangements were terminated as a result of the non-nuclear intra-system generation asset transfers completed on October 24, 2005.

Distribution revenues increased $43 million in 2005 compared with 2004 due to higher revenues in the residential sector ($44 million) and commercial sector ($2 million), partially offset by lower industrial revenues ($3 million). Higher distribution deliveries to residential and commercial customers due to warmer summer weather in 2005 were partially offset by lower unit prices. Revenues in the industrial sector decreased due to lower unit prices offsetting an increase in distribution deliveries.

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

4

Revenues from distribution throughput increased $3 million in 2004 compared with 2003. Distribution deliveries to commercial customers increased by $11 million in 2004 compared to 2003, reflecting increased KWH deliveries (2.1%) and higher unit prices. Lower unit prices offset the effect of higher throughput, resulting in a decrease of $9 million in revenues from industrial customers. The increased sales to the commercial and industrial sectors resulted from the improving economy in our service area.

  Under our Ohio transition plan, we provided incentives to customers to encourage switching to alternative energy providers. In 2005 and 2004, we provided additional shopping credits of $6 million and $16 million, respectively, from the prior year. These revenue reductions are deferred for future recovery under our transition plan and do not affect current period earnings.

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

Changes in KWH Sales	2005			2004
Increase (Decrease)
Electric Generation:
Retail		4.4	%		0.5	%
Wholesale		(5.2	)%		7.3	%
Total Electric Generation Sales		(0.2	)%		3.7	%
Distribution Deliveries:
Residential		7.1	%		1.7	%
Commercial		3.5	%		2.1	%
Industrial		3.3	%		0.4	%
Total Distribution Deliveries		4.7	%		1.3	%

Operating Expenses and Taxes

  Total operating expenses and taxes increased by $30 million in 2005 and by $22 million in 2004. The following table presents changes from the prior year by expense category:

Operating Expenses and Taxes - Changes	2005			2004
Increase (Decrease)	(In millions)
Fuel costs	$	(3	)	$	4
Purchased power costs		(31	)		56
Nuclear operating costs		(38	)		(57	)
Other operating costs		68			(27	)
Provision for depreciation		(14	)		5
Amortization of regulatory assets		46			18
Deferral of new regulatory assets		(51	)		(27	)
General taxes		13			10
Income taxes		40			40
Total operating expenses and taxes	$	30		$	22

Lower fuel costs in 2005, compared to 2004, resulted from decreased nuclear generation - down 4.5%. Purchased power costs decreased in 2005 due to lower unit costs offsetting an increase in KWH purchased to meet increased retail generation sales requirements. Lower nuclear operating costs in 2005 reflect the effect of lower owned/leased interests in the two plants (Beaver Valley Unit 2 - 55.62% and Perry - 35.24%) with refueling outages in 2005 as compared to Beaver Valley Unit 1 (100% owned) that had a refueling outage in 2004. In addition, nuclear operating costs incurred after the nuclear asset transfers were completed on December 16, 2005 were assumed by NGC. The increase in other operating costs in 2005 compared to 2004 was due to increased transmission expenses related to MISO Day 2 transactions that began on April 1, 2005.

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

5

The decrease in depreciation expense in 2005 compared to 2004 was attributable to revised estimated service life assumptions for fossil generating plants and a decrease in the depreciation of leased electric plant as a result of the intra-system generation asset transfer. The provision for depreciation increased in 2004 compared to 2003 primarily due to a slight change in the composite depreciation rate and a higher depreciable asset base. Increases in amortization of regulatory assets in 2005 and 2004 compared to the prior year resulted from higher amortization of Ohio transition regulatory assets. The higher deferrals of new regulatory assets in 2005 compared to 2004 primarily resulted from the PUCO-approved MISO cost deferrals and related interest ($49 million) (see Outlook - Regulatory Matters). The higher deferrals of new regulatory assets in 2004 compared to 2003 primarily reflected higher shopping incentive deferrals ($16 million) and related interest ($10 million).

General taxes increased by $13 million in 2005 and by $10 million in 2004 compared to the prior year, primarily due to higher property taxes and the effect of higher KWH sales which increased Ohio KWH excise tax and Pennsylvania gross receipts tax. Property taxes increased in 2005 due to the absence of a $6 million Pennsylvania property tax refund recognized in 2004 and increased in 2004 due to a property tax settlement in 2003.

On June 30, 2005, tax legislation was enacted in the State of Ohio that created a new CAT tax, which is based on qualifying “taxable gross receipts” that does not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax was effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and the personal property tax is phased-out over a four-year period at a rate of approximately 25% annually, beginning with the year ended 2005. During the phase-out period the Ohio income-based franchise tax will be computed consistent with the prior law, except that the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period. As a result of the new tax structure, all net deferred tax benefits that are not expected to reverse during the five-year phase-in period were written off as of June 30, 2005. The impact on income taxes associated with the required adjustment to net deferred taxes for 2005 was an additional tax expense of approximately $32 million, which was partially offset by the initial phase-out of the Ohio income-based franchise tax, which reduced income taxes by approximately $3 million in 2005.

Other Income

Other income decreased by $13 million in 2005 compared to 2004 due to a $8.5 million civil penalty payable to the DOJ and a $10 million liability for environmental projects recognized in connection with the W. H. Sammis Plant settlement (see Outlook - Environmental Matters), partially offset by higher interest income earned on associated company notes receivable. Other income increased $7 million in 2004 compared to 2003, primarily due to gains on disposition of property.

Net Interest Charges

Net interest charges continued to trend lower, decreasing by $1 million in 2005 and $44 million in 2004, compared to the prior year, due to our debt paydown program. Long-term debt interest was lower due to the redemption of $124 of pollution control notes in 2005. We also optionally redeemed $38 million of Penn’s preferred stock in 2005. We redeemed $165 million of long-term debt and remarketed $30 million of pollution control notes during 2004.

Cumulative Effect of Accounting Changes

Results in 2005 include an after-tax charge of $16 million recorded upon the adoption of FIN 47 in December 2005. We identified applicable legal obligations as defined under the new standard at our retired generating units, substation control rooms, service center buildings, line shops and office buildings, identifying asbestos as the primary conditional ARO. We recorded a conditional ARO liability of $27 million (including accumulated accretion for the period from the date the liability was incurred to the date of adoption), an asset retirement cost of $9 million(recorded as part of the carrying amount of the related long-lived asset), and accumulated depreciation of $9 million. We charged regulatory liabilities for $1 million upon adoption of FIN 47 for the transition amounts related to establishing the ARO for asbestos removal from substation control rooms and service center buildings. The remaining cumulative effect adjustment for unrecognized depreciation and accretion of $26 million was charged to income ($16 million, net of tax) for the year ended December 31, 2005. (See Note 11.)

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

6

Capital Resources and Liquidity

Our cash requirements in 2005 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions were met without increasing our net debt and preferred stock outstanding. During 2006, we expect to meet our contractual obligations with cash from operations. Borrowing capacity under credit facilities is available to manage working capital requirements. In connection with a plan to realign our capital structure, we plan to issue up to $600 million of new long-term debt in 2006. The proceeds are expected to be used as a return of equity capital to FirstEnergy. In subsequent years, we expect to use a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

As of December 31, 2005, our cash and cash equivalents of approximately $1 million remained unchanged from December 31, 2004.

Cash Flows From Operating Activities

Our net cash provided from operating activities during 2005, 2004 and 2003 are as follows:

Operating Cash Flows	2005			2004			2003
	(In millions)
Cash earnings (1)	$	755		$	776		$	689
Pension trust contribution (2)		(73	)		(44	)		--
Working capital and other		233			(316	)		382
Net cash provided from operating activities	$	915		$	416		$	1,071

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

⁽²⁾Pension trust contributions in 2005 and 2004 are net of $34 million and $29 million of income tax benefits, respectively.

Cash earnings, as disclosed 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)	$	314		$	343		$	325
Non-Cash Charges (Credits):
Provision for depreciation		109			122			118
Amortization of regulatory assets		457			411			393
Deferral of new regulatory assets		(151	)		(101	)		(73	)
Nuclear fuel and lease amortization		46			43			39
Deferred income taxes and investment tax credits, net*		(30	)		(73	)		(111	)
Cumulative effect of accounting changes		16			--			(32	)
Other non-cash charges		(6	)		31			30
Cash earnings (Non-GAAP)	$	755		$	776		$	689

* Excludes $29 million of deferred tax benefits from pension contributions in 2004.

Net cash flows from operating activities increased $499 million in 2005 compared to 2004 primarily due to a $549 million increase from changes in working capital and other, partially offset by a $29 million increase in after-tax voluntary pension trust contributions in 2005 compared to 2004 and a $21 million decrease in cash earnings for the reasons as described above under “Results from Operations”. The increase in working capital and other primarily reflects decreased outflows of $417 million from reduced tax payments and for accounts payable of $126 million plus $136 million of funds received in 2005 for pre-paid electric service (under a three-year Energy for Education Program with the Ohio Schools Council), partially offset by a decrease in cash provided from the settlement of accounts receivable of $124 million.

Net cash from operating activities decreased $655 million in 2004 compared to 2003 due to a $698 million decrease from changes in working capital and the $44 million after-tax voluntary pension trust contribution in 2004. These decreases were partially offset by an $87 million increase in cash earnings as described above under “Results from Operations.” The change in working capital primarily reflects decreases in accounts payable and accrued tax balances. In 2004 tax liabilities among affiliated companies were settled in accordance with the tax sharing agreement, reducing our accrued taxes by $249 million. Accrued taxes were also reduced by a $169 million federal income tax payment in 2004.

7

Cash Flows From Financing Activities

In 2005, 2004 and 2003, net cash used for financing activities of $728 million, $569 million and $982 million, respectively, primarily reflected the new issues and redemptions shown below:

Securities Issued or Redeemed	2005		2004			2003
	(In millions)
New Issues:
Pollution control notes	$	146	$	30		$	-
Unsecured notes		-		-			325
Long-term revolving credit		-		-			40
	$	146	$	30		$	365
Redemptions:
FMB	$	81	$	63		$	410
Pollution control notes		271		-			30
Secured notes		56		62			62
Preferred stock		38		1			1
Long-term revolving credit		-		40			-
Other, principally redemption premiums		6		6			17
	$	452	$	172		$	520
Short-term borrowings, net	$	26	$	(4	)	$	(225	)

Net cash used for financing activities increased to $728 million in 2005 from $569 million in 2004. The increase resulted from a net increase of $134 million in debt refinancings as shown above and a $25 million increase of common stock dividends to FirstEnergy. The $413 million decrease in net cash used for financing activities in 2004 from 2003 resulted from a net reduction of $234 million in debt refinancings as shown above and a $178 million reduction in common stock dividends to FirstEnergy.

We had approximately $522 million of cash and temporary cash investments (which include short-term notes receivable from associated companies) and $201 million of short-term indebtedness as of December 31, 2005. We have authorization from the PUCO to incur short-term debt of up to $500 million, which is expected to come from the bank facilities and the utility money pool described below. Penn has authorization from the SEC, continued by FERC rules adopted as a result of EPACT's repeal of PUHCA, to incur short-term debt up to its charter limit of $44 million (as of December 31, 2005 and will have access to bank facilities and the utility money pool).

OES Capital is a wholly owned subsidiary of OE whose borrowings are secured by customer accounts receivable purchased from OE. OES Capital can borrow up to $170 million ($30 million unused as of December 31, 2005) under a receivables financing arrangement. As a separate legal entity with separate creditors, OES Capital would have to satisfy its obligations to creditors before any of its remaining assets could be made available to OE.

Penn Power Funding LLC (Penn Funding), a wholly owned subsidiary of Penn, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Penn. Penn Funding can borrow up to the full amount of $25 million available as of December 31, 2005 under a receivables financing arrangement. As a separate legal entity with separate creditors, Penn Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Penn. On July 15, 2005, the facility was renewed until June 29, 2006.

As of December 31, 2005, we had the aggregate capability to issue approximately $429 million of additional FMB on the basis of property additions and retired bonds under the terms of our mortgage indentures. Our issuance of FMB is also subject to provisions of our senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit us to incur additional secured debt not otherwise permitted by a specified exception of up to $651 million as of December 31, 2005. Based upon applicable earnings coverage tests in our charters, we could issue a total of $3.1 billion of preferred stock (assuming no additional debt was issued) as of December 31, 2005.

On June 14, 2005, we, FirstEnergy, CEI, TE, JCP&L, Met-Ed, 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. Our borrowing limit under the facility is $500 million and Penn's is $50 million, subject in each case to applicable regulatory approvals.

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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 $605 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, debt to total capitalization as defined under the revolving credit facility was 38% for OE and 42% for Penn.

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 amount, 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 EUOC 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 EUOC 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 its subsidiaries to positive from stable. Fitch stated that the revision to FirstEnergy's outlook resulted from improved performance of the Company's generating fleet and ongoing debt reduction.

Our access to capital markets and costs of financing are influenced by the ratings of our securities. The following table displays FirstEnergy’s and the OE Companies’ 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-
Ohio Edison		Senior unsecured		BBB-		Baa2		BBB
		Preferred stock		BB+		Ba1		BBB-
Penn		Senior secured		BBB+		Baa1		BBB+
		Senior unsecured(1)		BBB-		Baa2		BBB
		Preferred stock		BB+		Ba1		BBB-

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

Cash Flows From Investing Activities

  Net cash used for investing activities totaled $188 million in 2005 compared to $152 million provided from investing activities in 2004. The $262 million change resulted primarily from the absence in 2005 of $278 million of cash proceeds from certificates of deposit in 2004, loan repayments made to associated companies and $78 million of investments for an escrow fund and a mortgage indenture deposit, partially offset by a $193 million increase in principal payments received on long-term notes receivable from associated companies. Net cash provided from investing activities increased by $260 million in 2004 from 2003. The change resulted primarily from the $278 million of certificates of deposit cash proceeds in 2004, a $62 million increase in loan repayments from associated companies and collection of principal on long-term notes receivable. These increases were partially offset by a $46 million increase in property additions.

Our capital spending for the period 2006-2010 is expected to be about $635 million, of which approximately $119 million applies to 2006. The capital spending is primarily for property additions supporting the distribution of electricity. In addition, there is capital spending for the leasehold interests in certain generating plants retained after the generation asset transfers.

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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)	$	1,306	$	3	$	185	$	4	$	1,114
Short-term borrowings		201		201		-		-		-
Capital leases		7		5		1		-		1
Operating leases (2)		1,120		86		194		204		636
Purchases (3)		36		14		12		9		1
Total	$	2,670	$	309	$	392	$	217	$	1,752

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

⁽²⁾ Operating lease payments are net of capital trust receipts of $475.8 million (see Note 6).

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

Off-Balance Sheet Arrangements

We have obligations that are not included on our Consolidated Balance Sheets related to the sale and leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2, which are satisfied through operating lease payments (see Note 6). The present value of these operating lease commitments, net of trust investments, was $652 million as of December 31, 2005.

Interest Rate Risk

Our exposure to fluctuations in market interest rates is reduced since a significant portion of our debt has fixed interest rates, as noted in the following table which presents principal amounts and related weighted average interest rates by year of maturity for our investment portfolio, debt obligations and preferred stock with mandatory redemption provisions.

Comparison of Carrying Value to Fair Value
																There-						Fair
Year of Maturity	2006			2007			2008			2009			2010			after			Total			Value
	(Dollars in millions)
Assets
Investments Other Than Cash
and Cash Equivalents-
Fixed Income	$	36		$	39		$	17		$	25		$	29		$	1,977		$	2,123		$	1,873
Average interest rate		8.1	%		8.2	%		8.2	%		8.5	%		8.6	%		5.0	%		5.3	%
Liabilities Long-term Debt and Other
Long-Term Obligations:
Fixed rate	$	3		$	6		$	179		$	2		$	65		$	318		$	573		$	576
Average interest rate		8.3	%		7.9	%		4.1	%		8.0	%		5.5	%		6.0	%		5.4	%
Variable rate																$	733		$	733		$	733
Average interest rate																	3.3	%		3.3	%
Short-term Borrowings	$	201																	$	201		$	201
Average interest rate		4.2	%																	4.2	%

Equity Price Risk

Included in our nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $67 million and $248 million as of December 31, 2005 and 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $7 million reduction in fair value as of December 31, 2005. As discussed in Note 5 - Fair Value of Financial Instruments, our nuclear decommissioning trust investments were transferred to NGC as part of the intra-system generation asset transfers with the exception of an amount related to our retained leasehold interests in nuclear generation assets.

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Outlook

  Our industry continues to transition to a more competitive environment and all of our customers can select alternative energy suppliers. We continue to deliver power to residential homes and businesses through our existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. In Ohio and Pennsylvania, we have a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits.

Regulatory Matters

Regulatory assets are costs which have been authorized by the PUCO, 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. Our regulatory assets were $0.8 billion and $1.1 billion as of December 31, 2005 and 2004, respectively. Penn had net regulatory liabilities of $59 million and $19 million as of December 31, 2005 and 2004, respectively, which are included in Other Noncurrent Liabilities on the Consolidated Balance Sheets as of December 31, 2005 and 2004.

On May 27, 2005, we filed an application with the PUCO to establish a GCAF rider under the RSP which had been approved by the PUCO in August 2004. The GCAF application sought recovery of increased fuel costs from 2006 through 2008 applicable to our retail customers through a tariff rider to be implemented January 1, 2006. The application reflected projected increases in fuel costs in 2006 compared to 2002 baseline costs. The new rider, after adjustments made in testimony, sought to recover all costs above the baseline (approximately $88 million in 2006 for all the Ohio Companies). Various parties including the OCC intervened in this case and the case was consolidated with the RCP application discussed below. On November 1, 2005, we filed tariffs in compliance with the RSP, which were approved by the PUCO on December 7, 2005.

On September 9, 2005, we filed an application with the PUCO that supplemented our existing RSP with an RCP which was designed to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. Major provisions of the RCP include:

· Maintain our existing level of base distribution rates through December 31, 2008;

· Defer and capitalize for future recovery with carrying charges certain distribution costs to be incurred by all the Ohio Companies during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three years;

· Adjust the RTC and Extended RTC recovery periods and rate levels so that full recovery of our authorized costs will occur as of December 31, 2008;

· Reduce our deferred shopping incentive balances as of January 1, 2006 by up to $75 million by accelerating the application of our accumulated cost of removal regulatory liability; and

· Recover increased fuel costs of up to $75 million, $77 million, and $79 million, in 2006, 2007, and 2008, respectively, from all OE and TE distribution and transmission customers through a fuel recovery mechanism. We may defer and capitalize increased fuel costs above the amount collected through the fuel recovery mechanism (in lieu of implementation of the GCAF rider).

The following table provides the estimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2006 through 2008:

Amortization
Period	Amortization
2006	$	169
2007		176
2008		198
Total Amortization	$	543

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On November 4, 2005, a supplemental stipulation was filed with the PUCO which was in addition to a stipulation filed with the September 9, 2005 application. On January 4, 2006, the PUCO approved the RCP filing with modifications. On January 10, 2006, the Ohio Companies filed a Motion for Clarification of the PUCO order approving the RCP. The Ohio Companies sought clarity on issues related to distribution deferrals, including requirements of the review process, timing for recognizing certain deferrals and definitions of the types of qualified expenditures. The Ohio Companies also sought confirmation that the list of deferrable distribution expenditures originally included in the revised stipulation fall within the PUCO order definition of qualified expenditures. On January 25, 2006, the PUCO issued an Entry on Rehearing granting in part, and denying in part, the Ohio Companies’ previous requests and clarifying issues referred to above. The PUCO granted the Ohio Companies’ requests to: 1) recognize fuel and distribution deferrals commencing January 1, 2006; 2) recognize distribution deferrals on a monthly basis prior to review by the PUCO Staff; 3) clarify that the types of distribution expenditures included in the Supplemental Stipulation may be deferred; and 4) clarify that distribution expenditures do not have to be “accelerated” in order to be deferred. The PUCO granted the Ohio Companies’ methodology for determining distribution deferral amounts, but denied the Motion in that the PUCO Staff must verify the level of distribution expenditures contained in current rates, as opposed to simply accepting the amounts contained in the Companies’ Motion. On February 3, 2006, several other parties filed applications for rehearing on the PUCO's January 4, 2006 Order. The Ohio Companies responded to the application for rehearing on February 13, 2006.

Under provisions of the RSP, the PUCO may require us to undertake, no more often than annually, a competitive bid process to secure generation for the years 2007 and 2008. On July 22, 2005, we filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approved by the PUCO for us in 2004 which resulted in the PUCO accepting no bids. Any acceptance of future competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and not until twelve months after the PUCO authorizes such termination. On September 28, 2005, the PUCO issued an Entry that essentially approved our filing but delayed the proposed timing of the competitive bid process by four months, calling for the auction to be held on March 21, 2006. OCC filed an application for rehearing of the September 28, 2005 Entry, which the PUCO denied on November 22, 2005. On February 23, 2006, the auction manager notified the PUCO that there was insufficient interest in the auction process to allow it to proceed in 2006.

On August 31, 2005, the PUCO approved our settlement stipulation for a rider to recover transmission and ancillary service-related costs beginning January 1, 2006, to be adjusted each July 1 thereafter. The incremental transmission and ancillary service revenues expected to be recovered from January through June 2006 are approximately $34 million, including recovery of the 2005 deferred MISO expenses as described below. In May 2006, we will file a modification to the rider to determine revenues from July 2006 through June 2007. On January 20, 2006, the OCC sought rehearing of the PUCO approval of the rider recovery during the period January 1, 2006 through June 30, 2006, as that amount pertains to recovery of the deferred costs. The PUCO denied the OCC's application on February 6, 2006. The OCC has sixty days from that date to appeal the PUCO's approval of the rider.

In response to our December 2004 application for authority to defer costs associated with transmission and ancillary service-related costs incurred during the period October 1, 2003 through December 31, 2005, the PUCO granted the accounting authority in May 2005 for us to defer incremental transmission and ancillary service-related charges incurred as a participant in MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 30, 2004 was denied. The PUCO also authorized us to accrue carrying charges on the deferred balances. On August 31, 2005, the OCC appealed the PUCO's decision. All briefs have been filed. A motion to dismiss filed on behalf of the PUCO is currently pending. Unless the court grants the motion, the appeal will be set for oral argument, which should be heard in the second half of 2006.

On October 11, 2005, Penn filed a plan with the PPUC to secure electricity supply for its customers at set rates following the end of its transition period on December 31, 2006. Penn is recommending that an RFP process cover the period January 1, 2007 through May 31, 2008. Hearings were held on January 10, 2006 with main briefs filed on January 27, 2006 and reply briefs on February 3, 2006. On February 17, 2006, the ALJ issued a Recommended Decision to adopt Penn's RFP process with modifications. A PPUC vote is expected in April 2006. Under Pennsylvania's electric competition law, we are required to secure generation supply for customers who do not choose alternative suppliers for their electricity.

We are proceeding with the implementation of the recommendations that 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) in late 2003 and early 2004, regarding enhancements to regional reliability that were to be completed subsequent to 2004. We 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, however, may 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 EPACT that could require additional, material expenditures. Finally, the PUCO is continuing to review our 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.

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In May 2004, the PPUC issued an order approving revised reliability benchmarks and standards, including revised benchmarks and standards for Met-Ed, Penelec and Penn. Met-Ed, Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004, 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 three Companies’ 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.

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.

We believe that we are 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, EPACT requires that all prudent costs incurred to comply with the new reliability standards be recovered in rates. If we are unable to meet the reliability standards for the bulk power system in the future, it could have a material adverse effect on our financial condition, results of operations and cash flows.

On November 1, 2005, FES filed two power sales agreements for approval with the FERC. One power sales agreement provided for FES to provide the PLR requirements of the Ohio Companies at a price equal to the retail generation rates approved by the PUCO for a period of three years beginning January 1, 2006. The Ohio Companies will be relieved of their obligation to obtain PLR power requirements from FES if the Ohio competitive bid process, mandated by the PUCO, results in a lower price for retail customers. A similar power sales agreement between FES and Penn permits Penn to obtain its PLR power requirements from FES at a fixed price equal to the retail generation price during 2006. Penn has filed a plan with the PPUC to use an RFP process to obtain its power supply requirements after 2006.

On December 29, 2005, the FERC issued an order setting the two power sales agreements for hearing. The order criticizes the Ohio competitive bid process, and requires FES to submit additional evidence in support of the reasonableness of the prices charged in the two power sales agreements. A pre-hearing conference was held on January 18, 2006 to determine the hearing schedule in this case. FES expects an initial decision to be issued in this case in the fall of 2006. The outcome of this proceeding cannot be predicted. FES has sought rehearing of the December 29, 2005 order.

See Note  9 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio and Pennsylvania and a detailed discussion of reliability initiatives, including initiatives by the PPUC, that impact Penn.

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Environmental Matters

  We accrue environmental liabilities only when we conclude 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.

  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. The report is available on our website at www.firstenergycorp.com/environmental.

W. H. Sammis Plant-

In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement was approved by the Court on July 11, 2005, and requires reductions of NO_x and SO₂ emissions at the W. H. Sammis Plant and other coal fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if we fail to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, we could be exposed to penalties under the settlement agreement. Capital expenditures necessary to meet those requirements are currently estimated to be $1.5 billion (the primary portion of which is expected to be spent in the 2008 to 2011 time period). On August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of sulfur dioxide emissions. The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy purchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million. Results in 2005 included the penalties payable by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized liabilities of $9.2 million and $0.8 million, respectively, for probable future cash contributions toward environmentally beneficial projects.

Other Legal Proceedings

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 herein.

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 concludes, among other things, that the problems leading to the outages began in our 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 our 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). We believe 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. We remain 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. We 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 our electric system. Our implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. We also are 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 we have not accrued a liability as of December 31, 2005 for any expenditures in excess of those actually incurred through that date. We note, however, that the FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review our 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.

14

FirstEnergy companies are also defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outage. Two cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of the four cases, the carriers seek reimbursement against various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company as well) for claims paid to insureds for claims allegedly arising as a result of the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. In addition to these six cases, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages. No estimate of potential liability has been undertaken for any of these cases.

We are 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. Although unable to predict the impact of these proceedings, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on our financial condition, results of operations and cash flows.

Nuclear Plant Matters-

As of December 16, 2005 NGC acquired ownership of the nuclear generation assets transferred from the OE, Penn, CEI and TE with the exception of leasehold interests of OE and TE in certain of the nuclear plants that are subject to sale and leaseback arrangements with non-affiliates. Excluding our retained leasehold interests in Beaver Valley Unit 2 (21.66%) and Perry (12.58%), the transfer included our prior owned interests in Beaver Valley Unit 1 (100%), Beaver Valley Unit 2 (33.96%) and Perry (22.66%).

On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee's failure to take prompt and corrective action. FENOC operates the Perry Nuclear Power Plant.

On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. By an inspection report dated January 18, 2006, the NRC closed one of the White Findings (related to emergency preparedness) which led to the multiple degraded cornerstones.

On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. The NRC reiterated this conclusion in its mid-year assessment letter dated August 30, 2005. On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance of Perry and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process, from increased oversight to possible impact to the plant’s operating authority. Although unable to predict a potential impact, its ultimate disposition could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

Other Legal Matters-

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005 additional information was requested regarding Davis-Besse. FirstEnergy has cooperated fully with the informal inquiry and continues to do so with the formal investigation.

15

                      On August 22, 2005, a class action complaint was filed against us in Jefferson County, Ohio Common Pleas Court seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from the W. H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members.

                      The City of Huron filed a complaint against OE with the PUCO challenging the ability of electric distribution utilities to collect transition charges from a customer of a newly formed municipal electric utility. The complaint was filed on May 28, 2003, and OE timely filed its response on June 30, 2003. In a related filing, the Ohio Companies filed for approval with the PUCO a tariff that would specifically allow the collection of transition charges from customers of municipal electric utilities formed after 1998. An adverse ruling could negatively affect full recovery of transition charges by the utility. Hearings on the matter were held in August 2005. Initial briefs from all parties were filed on September 22, 2005 and reply briefs were filed on October 14, 2005. It is unknown when the PUCO will decide this case.

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

  See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

Critical Accounting Policies

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

Regulatory Accounting

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

Revenue Recognition

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

Pension and Other Postretirement Benefits Accounting

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

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

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

In selecting an assumed discount rate, we consider currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to recent declines in corporate bond yields and interest rates in general, we reduced the assumed discount rate as of December 31, 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 returns 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 $107 million). As a result of our voluntary contribution and the increased market value of pension plan assets, we recognized a prepaid benefit cost of $225 million as of December 31, 2005. As prescribed by SFAS 87, we eliminated our additional minimum liability of $152 million and our intangible asset of $33 million. In addition, the entire AOCL balance was credited by $69 million (net of $49 million in 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 its health care plans, and projections of future medical trend rates. The effect on OE'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	%	$	1.4	$	0.8	$	2.2
Long-term return on assets		Decrease by 0.25	%	$	1.7	$	-	$	1.7
Health care trend rate		Increase by 1	%		na	$	5.2	$	5.2

Ohio Transition Cost Amortization

In connection with our Ohio transition plan, the PUCO determined allowable transition costs based on amounts recorded on our regulatory books. These costs exceeded those deferred or capitalized on our balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). We use an effective interest method for amortizing transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in our RSP. In computing the transition cost amortization, we include only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off-balance sheet costs and the return associated with these costs are recognized as income when received. Amortization of deferred customer shopping incentives and interest costs will be equal to the related revenue recovery that is recognized under the RCP (see Note 2 (A)).

Long-Lived Assets

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

17

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

 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 use 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

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 Issue and any impact on its 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.

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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 it to have a material impact on our financial statements.

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OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,		2005			2004			2003
	(In thousands)
OPERATING REVENUES (Note 2(I))		$	2,975,553		$	2,945,583		$	2,925,310
OPERATING EXPENSES AND TAXES:
Fuel			53,113			56,560			52,169
Purchased power (Note 2(I))			939,193			970,670			914,723
Nuclear operating costs			337,901			375,309			432,315
Other operating costs (Note 2(I))			404,763			336,772			363,989
Provision for depreciation			108,583			122,413			117,895
Amortization of regulatory assets			457,205			411,326			393,409
Deferral of new regulatory assets			(151,032	)		(100,633	)		(73,183	)
General taxes			193,284			180,523			170,078
Income taxes			297,160			257,114			216,979
Total operating expenses and taxes			2,640,170			2,610,054			2,588,374
OPERATING INCOME			335,383			335,529			336,936
OTHER INCOME (net of income taxes) (Notes 2(I))			61,243			74,077			66,782
NET INTEREST CHARGES:
Interest on long-term debt			58,709			59,465			91,068
Allowance for borrowed funds used during
construction and capitalized interest			(10,849	)		(7,211	)		(6,075	)
Other interest expense			16,679			12,026			22,340
Subsidiary's preferred stock dividend requirements			1,689			2,560			3,460
Net interest charges			66,228			66,840			110,793
INCOME BEFORE CUMULATIVE EFFECT
OF ACCOUNTING CHANGES			330,398			342,766			292,925
Cumulative effect of accounting changes (net of income taxes (benefit)
of ($9,223,000) and $22,389,000, respectively) (Note 2(G))			(16,343	)		-			31,720
NET INCOME			314,055			342,766			324,645
PREFERRED STOCK DIVIDEND REQUIREMENTS			2,635			2,502			2,732
EARNINGS ON COMMON STOCK		$	311,420		$	340,264		$	321,913
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

20

OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31,	2005		2004
	(In thousands)
ASSETS
UTILITY PLANT:
In service	$	2,526,851	$	5,440,374
Less - Accumulated provision for depreciation		984,463		2,716,851
		1,542,388		2,723,523
Construction work in progress -
Electric plant		58,785		203,167
Nuclear fuel		-		21,694
		58,785		224,861
		1,601,173		2,948,384
OTHER PROPERTY AND INVESTMENTS:
Investment in lease obligation bonds (Note 6)		325,729		354,707
Nuclear plant decommissioning trusts		103,854		436,134
Long-term notes receivable from associated companies		1,774,643		208,170
Other		44,210		48,579
		2,248,436		1,047,590
CURRENT ASSETS:
Cash and cash equivalents		929		1,230
Receivables-
Customers (less accumulated provision of $7,619,000 and $6,302,000,
respectively, for uncollectible accounts)		290,887		274,304
Associated companies		187,072		245,148
Other (less accumulated provisions of $4,000 and $64,000, respectively,
for uncollectible accounts)		15,327		18,385
Notes receivable from associated companies		520,762		538,871
Materials and supplies, at average cost		-		90,072
Prepayments and other		93,129		13,104
		1,108,106		1,181,114
DEFERRED CHARGES:
Regulatory assets		774,983		1,115,603
Prepaid pension costs		224,813		-
Property taxes		52,875		61,419
Unamortized sale and leaseback costs		55,139		60,242
Other		31,752		68,275
		1,139,562		1,305,539
	$	6,097,277	$	6,482,627
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity	$	2,502,191	$	2,493,809
Preferred stock not subject to mandatory redemption		60,965		60,965
Preferred stock of consolidated subsidiary not subject to mandatory redemption		14,105		39,105
Long-term debt and other long-term obligations		1,019,642		1,114,914
		3,596,903		3,708,793
CURRENT LIABILITIES:
Currently payable long-term debt		280,255		398,263
Short-term borrowings-
Associated companies		57,715		11,852
Other		143,585		167,007
Accounts payable-
Associated companies		172,511		187,921
Other		9,607		10,582
Accrued taxes		163,870		153,400
Accrued interest		8,333		11,992
Other		61,726		62,671
		897,602		1,003,688
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		769,031		766,276
Accumulated deferred investment tax credits		24,081		62,471
Asset retirement obligation		82,527		339,134
Retirement benefits		291,051		307,880
Deferred revenues - electric service programs		121,693		-
Other		314,389		294,385
		1,602,772		1,770,146
COMMITMENTS AND CONTINGENCIES (Notes 6 and 13)
	$	6,097,277	$	6,482,627
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.

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OHIO 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 175,000,000 shares-100 shares outstanding								$	2,297,253	$	2,098,729
Accumulated other comprehensive income (loss) (Note 2(F))									4,094		(47,118	)
Retained earnings (Note 10(A))									200,844		442,198
Total common stockholder's equity									2,502,191		2,493,809
		Number of Shares			Optional
		Outstanding		Redemption Price
		2005	2004		Per Share		Aggregate
PREFERRED STOCK NOT SUBJECT TO
MANDATORY REDEMPTION (Note 10(B)):
Cumulative, $100 par value-
Authorized 6,000,000 shares
3.90%		152,510	152,510	$	103.63	$	15,804		15,251		15,251
4.40%		176,280	176,280		108.00		19,038		17,628		17,628
4.44%		136,560	136,560		103.50		14,134		13,656		13,656
4.56%		144,300	144,300		103.38		14,917		14,430		14,430
Total		609,650	609,650				63,893		60,965		60,965
PREFERRED STOCK OF CONSOLIDATED
SUBSIDIARY NOT SUBJECT TO MANDATORY
REDEMPTION (Note 10(B)):
Pennsylvania Power Company-
Cumulative, $100 par value-
Authorized 1,200,000 shares
4.24%		40,000	40,000		103.13		4,125		4,000		4,000
4.25%		41,049	41,049		105.00		4,310		4,105		4,105
4.64%		60,000	60,000		102.98		6,179		6,000		6,000
7.75%		-	250,000				-		-		25,000
Total		141,049	391,049				14,614		14,105		39,105

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OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
As of December 31,	2005		2004						2005		2004		2005			2004
								(in thousands)
LONG-TERM DEBT AND OTHER
LONG-TERM OBLIGATIONS (Note 10(C)):
First mortgage bonds:
Ohio Edison Company-					Pennsylvania Power Company-
6.875% due 2005		-		80,000		9.740% due 2005-2019				13,669		14,643
						7.625% due 2023				6,500		6,500
Total first mortgage bonds		-		80,000						20,169		21,143		20,169			101,143
Secured notes:
Ohio Edison Company-					Pennsylvania Power Company-
7.680% due 2005		-		51,461			5.400% due 2013			1,000		1,000
*  3.050% due 2015		19,000		19,000			5.400% due 2017			10,600		10,600
6.750% due 2015		-		40,000		* 3.300% due 2017				17,925		17,925
*  3.250% due 2015		50,000		50,000			5.900% due 2018			16,800		16,800
*  3.200% due 2016		47,725		47,725			* 3.300% due 2021			10,525		14,482
7.050% due 2020		60,000		60,000			6.150% due 2023			12,700		12,700
*  1.700% due 2021		-		443			*3.610% due 2027			10,300		10,300
5.375% due 2028		13,522		13,522			5.375% due 2028			1,734		1,734
5.625% due 2029		-		50,000			5.450% due 2028			6,950		6,950
5.950% due 2029		-		56,212			6.000% due 2028			14,250		14,250
*  3.050% due 2029		100,000		-			5.950% due 2029			-		238
*  3.100% due 2029		6,450		-			1.800% due 2033			-		5,200
*  3.050% due 2030		60,400		60,400
*  3.350% due 2031		69,500		69,500
*  1.800% due 2033		-		44,800
*  3.100% due 2033		12,300		12,300
5.450% due 2033		14,800		14,800
*  3.350% due 2033		50,000		50,000
*  3.100% due 2033		108,000		108,000
Limited Partnerships-
7.32% weighted average
interest rate due 2005-2010		12,859		17,272
Total secured notes		624,556		765,435						102,784		112,179		727,340			877,614
Unsecured notes:
Ohio Edison Company-					Pennsylvania Power Company-
4.000% due 2008		175,000		175,000			*  3.500% due 2029			14,500		14,500
*  3.550% due 2014		50,000		50,000			5.390% due 2010            to associated            company
5.450% due 2015		150,000		150,000						62,900		-
*  3.850% due 2018		33,000		33,000
*  3.850% due 2018		23,000		23,000
*  3.750% due 2023		50,000		50,000
*  3.350% due 2033		-		30,000
Total unsecured notes		481,000		511,000		��				77,400		14,500		558,400			525,500
Preferred stock subject to mandatory redemption														-			12,750
Capital lease obligations (Note 6)														3,312			5,223
Net unamortized discount on debt														(9,324	)		(9,053	)
Long-term debt due within one year														(280,255	)		(398,263	)
Total long-term debt and other long-term obligations														1,019,642			1,114,914
TOTAL CAPITALIZATION													$	3,596,903		$	3,708,793
* Denotes variable rate issue with applicable year-end December 31, 2005 interest rate shown.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

23

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
								Accumulated
								Other
	Comprehensive			Number		Carrying		Comprehensive			Retained
	Income			of Shares		Value		Income (Loss)			Earnings
	(Dollars in thousands)
Balance, January 1, 2003					100	$	2,098,729	$	(59,495	)	$	800,021
Net income	$	324,645										324,645
Minimum liability for unfunded retirement
benefits, net of $2,014,000 of income taxes		2,674							2,674
Unrealized gain on investments, net of
$12,337,000 of income taxes		18,128							18,128
Comprehensive income	$	345,447
Cash dividends on preferred stock												(2,732	)
Cash dividends on common stock												(599,000	)
Balance, December 31, 2003					100		2,098,729		(38,693	)		522,934
Net income	$	342,766										342,766
Minimum liability for unfunded retirement
benefits, net of ($5,516,000) of income taxes		(7,552	)						(7,552	)
Unrealized loss on investments, net of
($533,000) of income taxes		(873	)						(873	)
Comprehensive income	$	334,341
Cash dividends on preferred stock												(2,502	)
Cash dividends on common stock												(421,000	)
Balance, December 31, 2004					100		2,098,729		(47,118	)		442,198
Net income	$	314,055										314,055
Minimum liability for unfunded retirement
benefits, net of $49,027,000 of income taxes		69,463							69,463
Unrealized loss on investments, net of
($13,068,000) of income taxes		(18,251	)						(18,251	)
Comprehensive income	$	365,267
Affiliated company asset transfers							198,147					(106,774	)
Restricted stock units							32
Preferred stock redemption adjustment							345
Cash dividends on preferred stock												(2,635	)
Cash dividends on common stock												(446,000	)
Balance, December 31, 2005					100	$	2,297,253	$	4,094		$	200,844

CONSOLIDATED STATEMENTS OF PREFERRED STOCK
	Not Subject to						Subject to
	Mandatory Redemption						Mandatory Redemption*
	Number			Par			Number			Par
	of Shares			Value			of Shares			Value
	(Dollars in thousands)
Balance, January 1, 2003		1,000,699		$	100,070			142,500		$	14,250
Redemptions-
7.625% Series								(7,500	)		(750	)
Balance, December 31, 2003		1,000,699			100,070			135,000			13,500
Redemptions-
7.625% Series								(7,500	)		(750	)
Balance, December 31, 2004		1,000,699			100,070			127,500			12,750
Redemptions-
7.750% Series		(250,000	)		(25,000	)
7.625% Series								(127,500	)		(12,750	)
Balance, December 31, 2005		750,699		$	75,070			-		$	-
* Preferred stock subject to mandatory redemption is classified as debt under SFAS 150.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

24

OHIO 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	$	314,055		$	342,766		$	324,645
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation		108,583			122,413			117,895
Amortization of regulatory assets		457,205			411,326			393,409
Deferral of new regulatory assets		(151,032	)		(100,633	)		(73,183	)
Nuclear fuel and lease amortization		45,769			42,811			39,317
Deferred lease costs		(6,365	)		(5,170	)		(4,183	)
Deferred income taxes and investment tax credits, net		(29,750	)		(44,469	)		(110,677	)
Accrued compensation and retirement benefits		14,506			35,840			33,065
Cumulative effect of accounting changes		16,343			-			(31,720	)
Pension trust contribution		(106,760	)		(72,763	)		-
Decrease (increase) in operating assets-
Receivables		84,688			209,130			170,492
Materials and supplies		(3,367	)		(10,259	)		(2,038	)
Prepayments and other current assets		(1,778	)		1,286			(2,586	)
Increase (decrease) in operating liabilities-
Accounts payable		45,149			(80,738	)		132,983
Accrued taxes		10,470			(406,945	)		94,281
Accrued interest		(3,659	)		(6,722	)		(9,495	)
Electric service prepayment programs		121,692			-			-
Other		(464	)		(21,519	)		(858	)
Net cash provided from operating activities		915,285			416,354			1,071,347
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		146,450			30,000			365,000
Short-term borrowings, net		26,404			-			-
Redemptions and Repayments-
Preferred stock		(37,750	)		(750	)		(750	)
Long-term debt		(414,020	)		(170,997	)		(519,506	)
Short-term borrowings, net		-			(4,015	)		(224,788	)
Dividend Payments-
Common stock		(446,000	)		(421,000	)		(599,000	)
Preferred stock		(2,635	)		(2,502	)		(2,732	)
Net cash used for financing activities		(727,551	)		(569,264	)		(981,776	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(266,823	)		(235,022	)		(189,019	)
Contributions to nuclear decommissioning trusts		(31,540	)		(31,540	)		(31,540	)
Loan repayments from (payments to) associated companies, net		(35,553	)		120,706			65,200
Collection of principal on long-term notes receivable		199,848			7,348			1,201
Proceeds from certificates of deposit		-			277,763			-
Other		(53,967	)		13,002			45,958
Net cash provided from (used for) investing activities		(188,035	)		152,257			(108,200	)
Net increase (decrease) in cash and cash equivalents		(301	)		(653	)		(18,629	)
Cash and cash equivalents at beginning of year		1,230			1,883			20,512
Cash and cash equivalents at end of year	$	929		$	1,230		$	1,883
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	67,239		$	65,765		$	103,632
Income taxes	$	285,819		$	419,123		$	250,564
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

25

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF TAXES
For the Years Ended December 31,	2005			2004			2003
	(In thousands)
GENERAL TAXES:
Ohio kilowatt-hour excise*	$	94,085		$	91,811		$	91,296
State gross receipts*		20,425			19,234			18,028
Real and personal property		67,438			58,000			51,074
Social security and unemployment		7,481			7,048			6,992
Other		3,855			4,430			2,688
Total general taxes	$	193,284		$	180,523		$	170,078
PROVISION FOR INCOME TAXES:
Currently payable-
Federal	$	265,875		$	246,865		$	270,345
State		73,870			75,907			81,505
		339,745			322,772			351,850
Deferred, net-
Federal		(60,252	)		(23,668	)		(57,503	)
State		36,798			(5,512	)		(16,038	)
		(23,454	)		(29,180	)		(73,541	)
Investment tax credit amortization		(15,519	)		(15,289	)		(14,747	)
Total provision for income taxes	$	300,772		$	278,303		$	263,562
INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income	$	297,160		$	257,114		$	216,979
Other income		12,835			21,189			24,194
Cumulative effect of accounting changes		(9,223	)		-			22,389
Total provision for income taxes	$	300,772		$	278,303		$	263,562
RECONCILIATION OF FEDERAL INCOME TAX
EXPENSE AT STATUTORY RATE TO TOTAL
PROVISION FOR INCOME TAXES:
Book income before provision for income taxes	$	614,827		$	621,069		$	588,207
Federal income tax expense at statutory rate	$	215,189		$	217,374		$	205,872
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits		(15,519	)		(15,289	)		(14,747	)
State income taxes, net of federal income tax benefit		71,935			45,757			42,554
Amortization of tax regulatory assets		7,341			6,130			6,144
Penalites		2,975			-			-
Competitive transition charge		31,934			27,889			27,075
Low income housing and franchise credits		(6,796	)		(8,615	)		(8,574	)
Other, net		(6,287	)		5,057			5,238
Total provision for income taxes	$	300,772		$	278,303		$	263,562
ACCUMULATED DEFERRED INCOME TAXES AS OF
DECEMBER 31:
Property basis differences	$	478,599		$	451,269		$	406,783
Allowance for equity funds used during construction		27,730			27,730			30,493
Regulatory transition charge		6,653			154,015			345,723
Asset retirement obligations		-			21,253			17,394
Customer receivables for future income taxes		33,946			39,266			44,382
Deferred sale and leaseback costs		(59,225	)		(63,432	)		(67,837	)
Unamortized investment tax credits		(9,605	)		(23,510	)		(29,031	)
Deferred gain for asset sale- affiliated companies		50,304			51,716			61,115
Other comprehensive income		2,689			(33,268	)		(27,219	)
Retirement benefits		30,849			(6,202	)		(29,676	)
Shopping incentive deferral		123,029			94,002			57,731
Other		84,062			53,437			57,833
Net deferred income tax liability	$	769,031		$	766,276		$	867,691
*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.

26

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.ORGANIZATION AND BASIS OF PRESENTATION:

The consolidated financial statements include OE (Company) and its wholly owned subsidiaries. Penn is the Company's principal operating subsidiary. The Company is a wholly owned subsidiary of FirstEnergy. FirstEnergy also holds directly all of the issued and outstanding common shares of its other principal electric utility operating subsidiaries, including CEI, TE, ATSI, JCP&L, Met-Ed and Penelec. In the fourth quarter of 2005, the Companies completed the intra-system transfers of their non-nuclear and nuclear generation assets to FGCO and NGC, respectively. See Note 14 - FirstEnergy Intra-System Generation Asset Transfers for further discussion.

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

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 Companies account for the effects of regulation through the application of SFAS 71 since their rates:

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

· are cost-based; and

· can be charged to and collected from customers.

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

Regulatory Assets-

The Companies recognize, as regulatory assets, costs which the FERC, PUCO and PPUC have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered from customers under the Companies' respective transition and rate restructuring plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those operations.

27

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

	2005*			2004*
	(In millions)
Regulatory transition costs	$	369		$	835
Customer shopping incentives		325			228
Customer receivables for future income taxes		88			99
Loss on reacquired debt		22			23
Asset removal costs		(80	)		(72	)
MISO transmission costs		49			-
Other		2			3
Total	$	775		$	1,116

* Penn had net regulatory liabilities of approximately $59 million and $19 million included in Other Noncurrent Liabilities on the Consolidated Balance Sheets as of December 31, 2005 and 2004, respectively.

The Company has been deferring customer shopping incentives and interest costs (Extended RTC) as new regulatory assets in accordance with its prior transition and rate stabilization plans. As a result of the RCP approved in January 2006, the Extended RTC balance ($325 million as of December 31, 2005) was reduced on January 1, 2006 by $75 million by accelerating the application of the Company's accumulated cost of removal regulatory liability against the Extended RTC balance. In accordance with the RCP, the recovery periods for the aggregate of the regulatory transition costs and the Extended RTC amounts were adjusted so that recovery of these aggregate amounts through the Company's RTC rate component began on January 1, 2006, with full recovery expected to be completed as of December 31, 2008. At the end of the recovery period, any remaining unamortized regulatory transition costs and Extended RTC balances will be eliminated, first, by applying any remaining cost of removal regulatory liability balance; any remaining regulatory transition costs and Extended RTC balances would be written off. In addition, the RCP allowed the Ohio Companies to defer and capitalize certain distribution costs during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the years 2006, 2007 and 2008. These deferrals will be recovered in distribution rates effective on or after January 1, 2009. See Note 9 for further discussion of the recovery of the shopping incentives and the new cost deferrals.

Transition Cost Amortization-

The Company amortizes transition costs (see Regulatory Matters - Ohio) using the effective interest method. Extended RTC amortization will be equal to the related revenue recovery that is recognized. The following table provides the estimated net amortization of regulatory transition costs and Extended RTC (including associated carrying charges) under the RCP for the period 2006 through 2008:

Amortization
Period	Amortization
	(In millions)
2006	$	169
2007		176
2008		198
Total Amortization	$	543

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

28

   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 Companies' customers. Total customer receivables were $291 million (billed - $177 million and unbilled - $114 million) and $274 million (billed - $172 million and unbilled - $102 million) as of December 31, 2005 and 2004, respectively.

(D)UTILITY PLANT AND DEPRECIATION-

Utility plant reflects original cost of construction (except for the Company’s nuclear leasehold interests which were adjusted to fair value) including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. The Companies' accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred.

The Companies provide for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annual composite rate for the Company's electric plant was approximately 2.1% in 2005, 2.3% in 2004 and 2.2% in 2003. The annual composite rate for Penn's electric plant was approximately 2.4% in 2005 and 2.2% in 2004 and 2003.

Asset Retirement Obligations

The Companies recognize a liability for retirement obligations associated with tangible assets in accordance with SFAS 143 and FIN 47. These standards require recognition of the fair value of a liability for an ARO in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and depreciated over time, as described further in Note 11, "Asset Retirement Obligations".

(E)ASSET IMPAIRMENTS-

Long-Lived Assets-

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

Investments-

The Company periodically evaluates its investments for impairment, including 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 5.

(F)COMPREHENSIVE INCOME-

Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholder's equity except those resulting from transactions with FirstEnergy and preferred stockholders. As of December 31, 2005, AOCL consisted of unrealized gains on investments in securities available for sale of $4 million. As of December 31, 2004, accumulated other comprehensive loss consisted of a minimum liability for unfunded retirement benefits of $69 million and unrealized gains on investments in securities available for sale of $22 million.

29

(G)CUMULATIVE EFFECT OF ACCOUNTING CHANGES-

   Results in 2005 include an after-tax charge of $16 million recorded upon the adoption of FIN 47 in December 2005. OE identified applicable legal obligations as defined under the new standard at its retired generating units, substation control rooms, service center buildings, line shops and office buildings, identifying asbestos as the primary conditional ARO. OE recorded a conditional ARO liability of $27 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption, an asset retirement cost of $9 million recorded as part of the carrying amount of the related long-lived asset, and offsetting accumulated depreciation of $9 million. OE charged regulatory liabilities for $1 million upon adoption of FIN 47 for the transition amounts related to establishing the ARO for asbestos removal from substation control rooms and service center buildings. The remaining cumulative effect adjustment for unrecognized depreciation and accretion of $26 million was charged to income ($16 million, net of tax). The adoption of FIN 47 had an immaterial impact on Penn’s year ended December 31, 2005 results. (See Note 11.)

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

(H)INCOME TAXES-

Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. The Company records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled. The Companies are included in FirstEnergy's consolidated federal income tax return. The consolidated tax liability is allocated on a "stand-alone" company basis, with the Companies recognizing any tax losses or credits they contribute to the consolidated return. (See Note 8 for Ohio Tax Legislation discussion).

(I)TRANSACTIONS WITH AFFILIATED COMPANIES-

Operating revenues, operating expenses and other income include transactions with affiliated companies, primarily ATSI, FES, NGC and FESC. The Ohio transition plan resulted in the corporate separation of FirstEnergy's regulated and unregulated operations in 2001. FES operates the generation businesses of the Companies, CEI and TE. As a result, the Companies had entered into power supply agreements (PSA) whereby FES purchased all of the Companies' nuclear generation. In the fourth quarter of 2005, the Companies, CEI and TE completed the intra-system transfers of their generation assets to FGCO and NGC (see Note 14). This resulted in the elimination of the fossil generating units lease arrangement and the nuclear generation PSA revenues with the exception of those revenues related to the leasehold interests (see Note 6) which were not included in the transfer. The Companies are now receiving interest income from FGCO and NGC on the associated companies notes received in exchange for the transferred net assets. The Companies continue to purchase their power from FES to meet their PLR obligations. In the fourth quarter of 2003, ATSI transferred operational control of its transmission facilities to MISO and previously affiliated transmission service expenses are now provided under the MISO Open Access Transmission Tariff. The primary affiliated companies transactions are as follows:

	2005		2004		2003
	(In millions)
Operating Revenues:
PSA revenues from FES	$	355	$	416	$	384
Generating units rent from FES		146		178		178
Ground lease with ATSI		12		12		12
Services Received:
Purchased power under PSA		938		970		902
Transmission expense		-		-		65
FESC support services		90		91		116
Other Income:
Interest income from ATSI		16		16		16
Interest income from FES		9		9		12
Interest income from FirstEnergy		22		-		-

30

FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Companies from FESC, a subsidiary of FirstEnergy. The 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 Companies' 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 contribution to its pension plan (Companies' share was $107 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 copayments, are also available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. The Companies recognize 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.

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

Obligations and Funded Status	Pension Benefits						Other Benefits
As of December 31
	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	)

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	)
Companies' share of net amount recognized	$	225		$	118		$	(291	)	$	(272	)
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

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	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
Companies' share of net periodic cost	$	-		$	7		$	24		$	28		$	28		$	43

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 Companies' pension trusts. The long-term rate of return is developed considering the portfolio’s asset allocation strategy.

FirstEnergy employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return 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 Increase		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 Companies recognized a prepaid pension cost of $225 as of December 31, 2005. As prescribed by SFAS 87, the Companies eliminated their additional minimum liability of $152 million and intangible asset of $33 million. In addition, the entire AOCL balance was credited by $69 million (net of $49 million of deferred taxes) as the fair value of trust assets exceeded the accumulated benefit obligation as of December 31, 2005.

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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.    ESOP:

  An ESOP Trust funds most of the matching contribution for FirstEnergy's 401(k) savings plan. All full-time employees eligible for participation in the 401(k) savings plan are covered by the ESOP. The ESOP borrowed $200 million from OE and acquired 10,654,114 shares of OE's common stock (subsequently converted to FirstEnergy common stock) through market purchases. Dividends on ESOP shares are used to service the debt. Shares are released from the ESOP on a pro rata basis as debt service payments are made. In 2005 the ESOP loan was refinanced ($66 million principal amount) and its term was extended by three years.

5.   FAIR VALUE OF FINANCIAL INSTRUMENTS:

Long-term Debt and Other Long-term Obligations-

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

	2005				2004
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Long-term debt	$	1,306	$	1,308	$	1,504	$	1,528
Preferred stock subject to mandatory redemption		-		-		13		12
	$	1,306	$	1,308	$	1,517	$	1,540

The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by a corporation with credit ratings similar to the Companies' ratings.

Investments-

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

	2005				2004
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Debt securities:(1)
-Government obligations	$	32	$	32	$	137	$	137
-Corporate debt securities(2)		2,091		1,841		609		708
-Mortgage-backed securities		-		-		1		1
		2,123		1,873		747		846
Equity securities(1)		104		104		289		289
	$	2,227	$	1,977	$	1,036	$	1,135

⁽¹⁾Includes nuclear decommissioning trust investments.

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

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

                    Investments other than cash and cash equivalents include held-to-maturity securities and available-for-sale securities. Decommissioning trust investments are classified as available-for-sale. As part of the intra-system nuclear generation asset transfers in the fourth quarter of 2005, the Companies transferred their decommissioning trust investments to NGC with the exception of a portion related to the OE's leasehold interests in the nuclear generation assets retained by the Company. The Companies have no securities held for trading purposes. The following table summarizes the amortized cost basis, gross unrealized gains and losses and fair values for decommissioning trust investments as of December 31:

	2005								2004
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
	(In millions)
Debt securities	$	37	$	-	$	-	$	37	$	186	$	3	$	1	$	188
Equity securities		61		9		3		67		205		49		6		248
	$	98	$	9	$	3	$	104	$	391	$	52	$	7	$	436

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	$	227	$	154	$	189
Gross realized gains		35		25		10
Gross realized losses		7		7		5
Interest and dividend income		13		13		10

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

	Less Than 12 Months				12 Months or More				Total
	Fair Value		Unrealized Losses		Fair Value		Unrealized Losses		Fair Value		Unrealized Losses
	(In millions)
Debt securities	$	15	$	-	$	6	$	-	$	21	$	-
Equity securities		11		1		6		2		17		3
	$	26	$	1	$	12	$	2	$	38	$	3

The Company periodically evaluates the securities held by its nuclear decommissioning trusts for other-than-temporary impairment. The Company considers the length of time and the extent to which the security's fair value has been less than its cost basis and other factors to determine whether an impairment is other than temporary. Unrealized gains and losses applicable to the Company's decommissioning trusts are recognized in OCI in accordance with SFAS 115, as fluctuations in the fair value of these trust balances will eventually affect earnings.

The investment policy for the nuclear decommissioning trust funds restricts or limits the ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust fund's custodian or managers and their parents or subsidiaries.

6.LEASES:

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

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The Company sold portions of its ownership interest in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on the portions sold for basic lease terms of approximately 29 years. Subsequent to the intra-system generation assets transfers in the fourth quarter of 2005, the Company continues to be responsible during the terms of the leases, to the extent of its individual leasehold interests, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. The Company has the right, at the end of the respective basic lease terms, to renew the leases for up to two years. The Company also has the right to purchase the facilities at the expiration of the basic lease term or any renewal term at a price equal to the fair market value of the facilities. The basic rental payments are adjusted when applicable federal tax law changes.

Consistent with the regulatory treatment, the rentals for capital and operating leases are charged to operating expenses on the Consolidated Statements of Income. Such costs for the three years ended December 31, 2005, are summarized as follows:

	2005		2004		2003
	(In millions)
Operating leases
Interest element	$	93.3	$	94.8	$	96.8
Other		52.3		50.4		43.9
Capital leases
Interest element		0.8		1.0		1.7
Other		1.9		1.6		1.4
Total rentals	$	148.3	$	147.8	$	143.8

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

				Operating Leases
						PNBV
	Capital			Lease		Capital
	Leases			Payments		Trusts		Net
	(In millions)
2006	$	4.2		$	145.4	$	59.5	$	85.9
2007		0.3			144.5		59.9		84.6
2008		0.3			144.4		34.9		109.5
2009		0.3			144.7		42.1		102.6
2010		0.3			144.9		43.2		101.7
Years thereafter		1.1			871.7		236.2		635.5
Total minimum lease payments		6.5		$	1,595.6	$	475.8	$	1,119.8
Executory costs		(2.1	)
Net minimum lease payments		4.4
Interest portion		(1.1	)
Present value of net minimum lease payments		3.3
Less current portion		(2.1	)
Noncurrent portion	$	1.2

The Company invested in PNBV, which was established to purchase a portion of the lease obligation bonds issued on behalf of lessors in the Company’s Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. The PNBV arrangement effectively reduces lease costs related to those transactions. OE has LOCs of $291 million and $134 million in connection with the sale and leaseback of Beaver Valley Unit 2 and Perry Unit 1, respectively.

7.VARIABLE INTEREST ENTITIES:

FIN 46R addresses the consolidation of VIEs, including special-purpose entities, that are not controlled through voting interests or in which the equity investors do not bear the 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.

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

PNBV was established to purchase a portion of the lease obligation bonds issued in connection with the Company's 1987 sale and leaseback of its interests in the Perry Plant and Beaver Valley Unit 2. The Company used debt and available funds to purchase the notes issued by PNBV. Ownership of PNBV includes a 3% equity interest by a unaffiliated third party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary of the Company.

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

The Company is exposed to losses under the sale-leaseback agreements upon the occurrence of certain contingent events that it considers unlikely to occur. The Company has a maximum exposure to loss under these provisions of approximately $1 billion, which represents the net amount of casualty value payments upon the occurrence of specified casualty events that render the applicable plant worthless. Under the sale and leaseback agreement, the Company has net minimum discounted lease payments of $652 million that would not be payable if the casualty value payments are made.

8.      OHIO TAX LEGISLATION:

On June 30, 2005, tax legislation was enacted in the State of Ohio that created a new CAT tax, which is based on qualifying “taxable gross receipts” and does not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax was effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and the personal property tax is phased-out over a four-year period at a rate of approximately 25% annually, beginning with the year ended 2005. During the phase-out period the Ohio income-based franchise tax will be computed consistent with the prior tax law, except that the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period. As a result of the new tax structure, all net deferred tax benefits that were not expected to reverse during the five-year phase-in period were written-off as of June 30, 2005. The increase to income taxes associated with the adjustment to net deferred taxes in 2005 was $32 million. Income tax expenses were reduced by $3 million during 2005 by the initial phase-out of the Ohio income-based franchise tax and phase-in of the CAT tax.

9. 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.

In May 2004, the PPUC issued an order approving revised reliability benchmarks and standards, including revised benchmarks and standards for Met-Ed, Penelec and Penn. Met-Ed, Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004, 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 three Companies’ 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.

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.

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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.

On November 1, 2005, FES filed two power sales agreements for approval with the FERC. One power sales agreement provided for FES to provide the PLR requirements of the Ohio Companies at a price equal to the retail generation rates approved by the PUCO for a period of three years beginning January 1, 2006. The Ohio Companies will be relieved of their obligation to obtain PLR power requirements from FES if the Ohio competitive bid process results in a lower price for retail customers. A similar power sales agreement between FES and Penn permits Penn to obtain its PLR power requirements from FES at a fixed price equal to the retail generation price during 2006. Penn has filed a plan with the PPUC to use an RFP process to obtain its power supply requirements after 2006.

On December 29, 2005, the FERC issued an order setting the two power sales agreements for hearing. The order criticizes the Ohio competitive bid process, and requires FES to submit additional evidence in support of the reasonableness of the prices charged in the Ohio and Pennsylvania Contracts. A pre-hearing conference was held on January 18, 2006 to determine the hearing schedule in this case. FES expects an initial decision to be issued in this case in the fall of 2006. The outcome of this proceeding cannot be predicted. FES has sought rehearing of the December 29, 2005 order.

Ohio-

On August 5, 2004, the Company accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a competitive bid process. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Company's transition plan market development period. In October 2004, the OCC and NOAC filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order in this proceeding as well as the associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral arguments on the appeals and it is expected that the Court will issue its opinion in 2006. On November 1, 2005, the Company filed tariffs in compliance with the approved RSP, which were approved by the PUCO on December 7, 2005.

On May 27, 2005, the Company filed an application with the PUCO to establish a GCAF rider under the RSP. The GCAF application sought recovery of increased fuel costs from 2006 through 2008 applicable to the Company's retail customers through a tariff rider to be implemented January 1, 2006. The application reflected projected increases in fuel costs in 2006 compared to 2002 baseline costs. The new rider, after adjustments made in testimony, sought to recover all costs above the baseline (approximately $88 million in 2006 for all the Ohio Companies). Various parties including the OCC intervened in this case and the case was consolidated with the RCP application discussed below.

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On September 9, 2005, the Company filed an application with the PUCO that supplemented its existing RSP with an RCP which was designed to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. Major provisions of the RCP include:

·   Maintain the existing level of base distribution rates through December 31, 2008 for OE;

· Defer and capitalize for future recovery with carrying charges certain distribution costs to be incurred by all the Ohio Companies during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three years;

· Adjust the RTC and Extended RTC recovery periods and rate levels so that full recovery of authorized costs will occur as of December 31, 2008 for OE;

· Reduce the deferred shopping incentive balances as of January 1, 2006 by up to $75 million for OE by accelerating the application of its accumulated cost of removal regulatory liability; and

· Recover increased fuel costs of up to $75 million, $77 million, and $79 million, in 2006, 2007, and 2008, respectively, from all OE and TE distribution and transmission customers through a fuel recovery mechanism. The Company may defer and capitalize increased fuel costs above the amount collected through the fuel recovery mechanism (in lieu of implementation of the GCAF rider).

On November 4, 2005, a supplemental stipulation was filed with the PUCO which was in addition to a stipulation filed with the September 9, 2005 application. On January 4, 2006, the PUCO approved the RCP filing with modifications. On January 10, 2006, the Company filed a Motion for Clarification of the PUCO order approving the RCP. The Company sought clarity on issues related to distribution deferrals, including requirements of the review process, timing for recognizing certain deferrals and definitions of the types of qualified expenditures. The Company also sought confirmation that the list of deferrable distribution expenditures originally included in the revised stipulation fall within the PUCO order definition of qualified expenditures. On January 25, 2006, the PUCO issued an Entry on Rehearing granting in part, and denying in part, the Company's previous requests and clarifying issues referred to above. The PUCO granted the Ohio Company's requests to: 1) recognize fuel and distribution deferrals commencing January 1, 2006; 2) recognize distribution deferrals on a monthly basis prior to review by the PUCO Staff; 3) clarify that the types of distribution expenditures included in the Supplemental Stipulation may be deferred; and 4) clarify that distribution expenditures do not have to be “accelerated” in order to be deferred. The PUCO granted the Company's methodology for determining distribution deferral amounts, but denied the Motion in that the PUCO Staff must verify the level of distribution expenditures contained in current rates, as opposed to simply accepting the amounts contained in the Company's Motion. On February 3, 2006, several other parties filed applications for rehearing on the PUCO's January 4, 2006 Order. The Company responded to the application for rehearing on February 13, 2006.

Under provisions of the RSP, the PUCO may require the Company to undertake, no more often than annually, a competitive bid process to secure generation for the years 2007 and 2008. On July 22, 2005, FirstEnergy filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approved by the PUCO for the Company in 2004, which resulted in the PUCO accepting no bids. Any acceptance of future competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and not until twelve months after the PUCO authorizes such termination. On September 28, 2005, the PUCO issued an Entry that essentially approved the Company's filing but delayed the proposed timing of the competitive bid process by four months, calling for the auction to be held on March 21, 2006. OCC filed an application for rehearing of the September 28, 2005 Entry, which the PUCO denied on November 22, 2005. On February 23, 2006, the auction manager notified the PUCO that there was insufficient interest in the auction process to allow it to proceed in 2006.

On December 30, 2004, the Company filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application sought recovery of these costs beginning January 1, 2006. The Company requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. The PUCO approved the settlement stipulation on August 31, 2005. The incremental transmission and ancillary service revenues expected to be recovered from January through June 2006 are approximately $34 million. This amount includes the recovery of the 2005 deferred MISO expenses as described below. In May 2006, the Company will file a modification to the rider to determine revenues from July 2006 through June 2007.

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 The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for the Company to defer incremental transmission and ancillary service-related charges incurred as a participant in MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 30, 2004 was denied. The PUCO also authorized the Company to accrue carrying charges on the deferred balances. On August 31, 2005, the OCC appealed the PUCO's decision. All briefs have been filed. A motion to dismiss filed on behalf of the PUCO is currently pending. Unless the court grants the motion, the appeal will be set for oral argument, which should be heard in the third or fourth quarter of 2006.

On January 20, 2006 the OCC sought rehearing of the PUCO approval of the rider recovery during the period January 1, 2006 through June 30, 2006, as that amount pertains to recovery of the deferred costs. The PUCO denied the OCC's application on February 6, 2006. The OCC has sixty days from that date to appeal the PUCO's approval of the rider.

Pennsylvania-

On October 11, 2005, Penn filed a plan with the PPUC to secure electricity supply for its customers at set rates following the end of its transition period on December 31, 2006. Penn is recommending that the RFP process cover the period January 1, 2007 through May 31, 2008. Hearings were held on January 10, 2006 with Main Briefs filed on January 27, 2006 and Reply Briefs on February 3, 2006. On February 17, 2006, the ALJ issued a Recommended Decision to adopt Penn's RFP process with modifications. A PPUC vote is expected in April 2006. Under Pennsylvania's electric competition law, Penn is required to secure generation supply for customers who do not choose alternative suppliers for their electricity

10.CAPITALIZATION:

(A)RETAINED EARNINGS-

Under the Company’s first mortgage indenture, the Company’s consolidated retained earnings unrestricted for payment of cash dividends on the Company’s common stock were $197 million as of December 31, 2005.

(B)PREFERRED AND PREFERENCE STOCK-

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

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

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

Other Long-term Debt-

Each of the Companies has a first mortgage indenture under which it issues FMB secured by a direct first mortgage lien on substantially all of its property and franchises, other than specifically excepted property. The Company also has a 1998 general mortgage under which it issues mortgage bonds based upon the pledge of a like amount of FMB as security. These mortgage bonds therefore effectively enjoy the same lien on that property and are referred to as FMB herein. The Companies have various debt covenants under their respective financing arrangements. The most restrictive of their debt covenants relate to the nonpayment of interest and/or principal on debt which could trigger a default and the maintenance of minimum fixed charge ratios and debt to capitalization ratios. There also exists cross-default provisions among financing arrangements of FirstEnergy and the Companies.

Based on the amount of FMB authenticated by the respective mortgage bond trustees through December 31, 2005, the Company's annual sinking fund requirements for all FMB issued under the various mortgage indentures amounts to $30 million. The Company expects to deposit funds with its mortgage bond trustee in 2006 that will then be withdrawn upon the surrender for cancellation of a like principal amount of FMB, specifically authenticated for such purposes against unfunded property additions or against previously retired FMB. This method can result in minor increases in the amount of the annual sinking fund requirement.

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

	(In millions)
2006	$	278
2007		6
2008		229
2009		2
2010		65

Included in the table above are amounts for various variable interest rate long-term debt that have provisions by which individual debt holders are required to "put back" the respective debt to the issuer for redemption prior to its maturity date. These amounts are $221 million and $50 million in 2006 and 2008, respectively, representing the next times the debt holders may exercise this provision.

The Companies' obligations to repay certain pollution control revenue bonds are secured by several series of FMB. Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank LOCs of $158 million and noncancelable municipal bond insurance policies of $749 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the LOCs or the policies, the Companies are entitled to a credit against their obligation to repay those bonds. The Companies pay annual fees of 1.7% of the amounts of the LOCs to the issuing bank and are 0.20% to 0.60% of the amounts of the policies to the insurers and are obligated to reimburse the bank or insurers, as the case may be, for any drawings thereunder.

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

11.ASSET RETIREMENT OBLIGATIONS:

In January 2003, the Companies 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. Upon retirement, a gain or loss would be recognized if the cost to settle the retirement obligation differs from the carrying amount.

The Companies initially identified applicable legal obligations as defined under the standard for nuclear power plant decommissioning of Beaver Valley and Perry nuclear generating facilities and reclamation of a sludge disposal pond related to the Bruce Mansfield Plant. The ARO liability as of the date of adoption was $298 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. The Companies' share of the obligation to decommission these units was developed based on site specific studies performed by an independent engineer. The Companies utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.

Pursuant to the generation asset transfers on October 24, 2005 and December 16, 2005, FGCO and NGC now own nearly all of the fossil and nuclear generation assets, respectively, previously owned by the Companies. The generating plant interests transferred do not include leasehold interests of the Company that are currently subject to sale and leaseback arrangements with non-affiliates (See Note 14). As a result, only the ARO associated with sale and leaseback arrangements remain with the Company.

In 2005, the Companies revised the ARO associated with Beaver Valley Unit 2 and Perry as a result of an updated decommissioning study. The present value of revisions in the estimated cash flows associated with projected decommissioning costs connected with the assets subject to sale and leaseback arrangements decreased the ARO and corresponding plant asset for Beaver Valley Unit 2 and Perry by $5 million and $6 million, respectively.

The Company continues to maintain the nuclear decommissioning trust funds associated with the sale and leaseback arrangements 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 $104 million.

   The Companies 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 for conditional ARO under FIN 47 is the same as described above for SFAS 143.

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   The Company identified applicable legal obligations as defined under the new standard at its retired generating units, 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 $27 million (including accumulated accretion for the period from the date the liability was incurred to the date of adoption), an asset retirement cost of $9 million (recorded as part of the carrying amount of the related long-lived asset) and accumulated depreciation of $9 million. The Company recognized a regulatory liability of $1 million upon adoption of FIN 47 for the transition amounts related to establishing the ARO for asbestos removal from substation control room and service center buildings, therefore requiring a $26 million cumulative effect adjustment ($16 million net of tax) for unrecognized depreciation and accretion to be recorded as of December 31, 2005. The obligation to remediate asbestos, lead paint abatement and other remediation costs at the retired generating units was developed based on site specific studies performed by an independent engineer. The costs of remediation at the substation control rooms, service center buildings, line shops and office buildings were based on costs incurred during recent remediation projects performed at each of these locations, respectively. The conditional ARO liability was the 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 adoption of FIN 47 had an immaterial impact on Penn’s year ended December 31, 2005 results. 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	$	339			318
Transfers to FGCO and NGC		(293	)		-
Accretion		21			21
Revisions in estimated cash flows		(11	)		-
FIN 47 ARO		27			-
Balance at end of year	$	83			339

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

Short-term borrowings outstanding as of December 31, 2005, consisted of $4 million of OE bank borrowings, $140 million of OES Capital, Incorporated and $58 million of borrowings from affiliates. OES Capital is a wholly owned subsidiary of OE whose borrowings are secured by customer accounts receivable purchased from OE. OES Capital can borrow up to $170 million under a receivables financing arrangement at rates based on certain bank commercial paper and is required to pay an annual fee of 0.20% on the amount of the entire finance limit. The receivables financing agreement expired in February 2006 and was renewed until October 2006. Penn Funding, a wholly owned subsidiary of Penn, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Penn. It can borrow up to $25 million under a receivables financing arrangement at rates based on bank commercial paper rates. The financing arrangements require payment of an annual facility fee of 0.15% on the entire finance limit. Penn's receivables financing agreements expire in June 2006. As separate legal entities with separate creditors, OES Capital and Penn Funding would have to satisfy their separate obligations to creditors before any of their remaining assets could be made available to OE and Penn, respectively.

In June 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, 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. OE's and Penn’s combined borrowing limits under the facility are $550 million.

The weighted average interest rates on short-term borrowings outstanding as of December 31, 2005 and 2004 were 4.2% and 2.3%, respectively.

13.COMMITMENTS AND CONTINGENCIES:

(A)NUCLEAR INSURANCE-

The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $10.8 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. Based on its leasehold interests in the Beaver Valley Unit 2 and the Perry Plant, the Company’s maximum potential assessment under the industry retrospective rating plan (assuming the other affiliate co-owners contribute their proportionate shares of any assessments under the retrospective rating plan) would be $34.4 million per incident but not more than $5.1 million in any one year for each incident.

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The Company is also insured as to its respective interests in Beaver Valley and Perry under policies issued to the operating company for each plant. Under these policies, up to $2.75 billion is provided for property damage and decontamination and decommissioning costs. The Company has also obtained approximately $149.8 million of insurance coverage for replacement power costs for its respective leasehold interests in Beaver Valley and Perry. Under these policies, the Company can be assessed a maximum of approximately $8.1 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses.

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

(B)ENVIRONMENTAL MATTERS-

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

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

W. H. Sammis Plant

In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement was approved by the Court on July 11, 2005, and requires reductions of NO_x and SO₂ emissions at the W. H. Sammis Plant and other coal fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if OE and Penn fail to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, OE and Penn could be exposed to penalties under the settlement agreement. Capital expenditures necessary to meet those requirements are currently estimated to be $1.5 billion (the primary portion of which is expected to be spent in the 2008 to 2011 time period). On August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of sulfur dioxide emissions. The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy purchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million. Results in 2005 included the penalties payable by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized liabilities of $9.2 million and $0.8 million, respectively, for probable future cash contributions toward environmentally beneficial projects.

(C)OTHER LEGAL PROCEEDINGS-

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.

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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.

FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outage. Two cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of the four cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company as well) for claims paid to insureds for claims allegedly arising as a result of the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. In addition to these six cases, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages. No estimate of potential liability has been undertaken for any of these cases.

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. Although unable to predict the impact of these proceedings, 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.

Nuclear Plant Matters-

As of December 16, 2005 NGC acquired ownership of the nuclear generation assets transferred from the Companies, CEI and TE with the exception of leasehold interests of the Company and TE in certain of the nuclear plants that are subject to sale and leaseback arrangements with non-affiliates. Excluding the Company's retained leasehold interests in Beaver Valley Unit 2 (21.66%) and Perry (12.58%), the transfer included the Companies' prior owned interests in Beaver Valley Unit 1 (100.00%), Beaver Valley Unit 2 (33.96%) and Perry (22.66%).

On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee's failure to take prompt and corrective action. FENOC operates the Perry Nuclear Power Plant.

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On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. By an inspection report dated January 18, 2006, the NRC closed one of the White Findings (related to emergency preparedness) which led to the multiple degraded cornerstones.

On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. The NRC reiterated this conclusion in its mid-year assessment letter dated August 30, 2005. On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance of Perry and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process, from increased oversight to possible impact to the plant’s operating authority. Although unable to predict a potential impact, its ultimate disposition could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

Other Legal Matters-

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005 additional information was requested regarding Davis-Besse. FirstEnergy has cooperated fully with the informal inquiry and continues to do so with the formal investigation.

On August 22, 2005, a class action complaint was filed against the Company in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from W. H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members.

The City of Huron filed a complaint against OE with the PUCO challenging the ability of electric distribution utilities to collect transition charges from a customer of a newly formed municipal electric utility. The complaint was filed on May 28, 2003, and OE timely filed its response on June 30, 2003. In a related filing, the Ohio Companies filed for approval with the PUCO a tariff that would specifically allow the collection of transition charges from customers of municipal electric utilities formed after 1998. An adverse ruling could negatively affect full recovery of transition charges by the utility. Hearings on the matter were held in August 2005. Initial briefs from all parties were filed on September 22, 2005 and reply briefs were filed on October 14, 2005. It is unknown when the PUCO will decide this case.

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

14.     FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS:

On May 13, 2005, Penn, and on May 18, 2005, the Ohio Companies entered into certain agreements implementing a series of intra-system generation asset transfers that were completed in the fourth quarter of 2005. The asset transfers resulted in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and FGCO, respectively. The generating plant interests transferred do not include OE’s leasehold interests in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.

On October 24, 2005, the Companies completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to FGCO's purchase option under the Master Facility Lease.

The difference (approximately $177.7 million) between the purchase price specified in the Master Facility Lease and the net book value at the date of transfer was credited to equity. FGCO also assumed certain assets and liabilities relating to the purchased units. As consideration, FGCO delivered to OE and Penn promissory notes of approximately $1.0 billion and $0.1 billion, respectively, that are secured by liens on the units purchased, bear interest at a rate per annum based on the weighted cost of OE’s and Penn's long-term debt (3.98% and 5.39%, respectively) and mature twenty years after the date of issuance. FGCO may pre-pay a portion of the promissory notes through refunding from time to time of OE’s and Penn's outstanding pollution control debt. The timing of any refunding will be subject to market conditions and other factors.

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 On December 16, 2005, the Companies completed the intra-system transfer of their respective ownership in the nuclear generation assets to NGC through an asset spin-off by way of dividend. FENOC continues to operate and maintain the nuclear generation assets.

The purchase price of the generation assets was the net book value as of September 30, 2005. The difference (approximately $20.5 million) between the purchase price and the net book value at the date of transfer was credited to equity. Pursuant to the OE Contribution Agreement, OE made a capital contribution to NGC of its undivided ownership interests in certain nuclear generation assets, the common stock of OES Nuclear Incorporated (OES Nuclear), a wholly owned subsidiary of OE that held an undivided interest in the Perry Nuclear Power Plant, together with associated decommissioning trust funds and other related assets. In connection with the contribution, NGC assumed other liabilities associated with the transferred assets. In addition, OE and Penn received promissory notes from NGC in the principal amount of approximately $371.5 million and $240.4 million, respectively, representing the net book value of the contributed assets as of September 30, 2005, less other liabilities assumed. The notes bear interest at a rate per annum based on OE’s and Penn's weighted average cost of long-term debt (3.98% and 5.39%, respectively), mature twenty years from the date of issuance, and are subject to prepayment at any time, in whole or in part, by NGC. Following the capital contribution, OES Nuclear was merged with and into NGC, and OE distributed the common stock of NGC as a dividend (approximately $106.8 million) to FirstEnergy, such that NGC is currently a direct wholly owned subsidiary of FirstEnergy.

These transactions were pursuant to the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. The transactions essentially completed the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants.

The transfers are expected to affect the Companies' near-term future results with reductions in revenues and expenses. Revenues will be reduced due to the termination of the sale of the Companies' nuclear-generated KWH and the lease of their non-nuclear generation assets arrangements with FES. The Companies' expenses will be lower due to the nuclear fuel and operating costs assumed by NGC as well as depreciation and property tax expenses assumed by FGCO and NGC related to the transferred generating assets. OE will retain the nuclear-generated KWH sales arrangement and the portion of expenses related to its retained leasehold interests in Perry and Beaver Valley Unit 2. In addition, the Companies will receive interest income from associated company notes receivable from FGCO and NGC for the transfer of their generation net assets and eliminate the interest expense on certain pollution control notes to be transferred to FGCO and NGC. FES will continue to provide the PLR requirements of the Companies under revised purchased power arrangements for a three-year period beginning January 1, 2006 (see Note 9 - Regulatory Matters).

       The following table provides the value of assets transferred along with the related liabilities:

Assets Transferred (In millions)
Property, plant and equipment	$	1,592
Other property and investments		372
Current assets		94
Deferred charges		-
	$	2,058
Liabilities Related to Assets Transferred
Long-term debt	$	104
Current liabilities		-
Noncurrent liabilities		261
	$	365
Net Assets Transferred	$	1,693

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

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

In November 2004, the FASB issued this statement to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be “so abnormal” that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by the Companies beginning January 1, 2006. The Company does not expect it to have a material impact on its financial statements.

16.     SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):

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

	March 31,		June 30,		September 30,		December 31,
Three Months Ended	2005		2005		2005		2005
	(In millions)
Operating Revenues	$	726.3	$	716.6	$	825.8	$	706.8
Operating Expenses and Taxes		653.4		667.2		700.1		619.4
Operating Income		72.9		49.4		125.7		87.4
Other Income		0.5		16.9		20.0		23.9
Net Interest Charges		16.6		19.2		14.3		16.2
Income before cumulative effect of accounting change		56.8		47.1		131.4		95.1
Cumulative Effect of Accounting Change (Net of Income Tax Benefit)		-		-		-		(16.3	)
Net Income	$	56.8	$	47.1	$	131.4	$	78.8
Earnings on Common Stock	$	56.1	$	46.4	$	130.7	$	78.1

	March 31,		June 30,		September 30,		December 31,
Three Months Ended	2004		2004		2004		2004
	(In millions)
Operating Revenues	$	743.3	$	718.4	$	766.3	$	717.6
Operating Expenses and Taxes		660.9		632.2		670.8		646.2
Operating Income		82.4		86.2		95.5		71.4
Other Income		12.5		20.7		17.2		23.7
Net Interest Charges		18.8		19.5		10.0		18.6
Net Income	$	76.1	$	87.4	$	102.7	$	76.5
Earnings on Common Stock	$	75.5	$	86.7	$	102.1	$	76.0

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