THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

2005 ANNUAL REPORT TO STOCKHOLDERS

The Cleveland Electric Illuminating Company is a wholly owned electric utility operating subsidiary of FirstEnergy Corp. It engages in the distribution and sale of electric energy in an area of approximately 1,700 square miles in northeastern Ohio. It also engages in the sale, purchase and interchange of electric energy with other electric companies. The area it serves has a population of approximately 1.9 million.

Contents	Page
Glossary of Terms		i-ii
Report of Independent Registered Public Accounting Firm		1
Selected Financial Data		2
Management's Discussion and Analysis		3-18
Consolidated Statements of Income		19
Consolidated Balance Sheets		20
Consolidated Statements of Capitalization		21
Consolidated Statements of Common Stockholder's Equity		22
Consolidated Statements of Preferred Stock		22
Consolidated Statements of Cash Flows		23
Consolidated Statements of Taxes		24
Notes to Consolidated Financial Statements		25-44

GLOSSARY OF TERMS

The following abbreviations and acronyms are used in this report to identify The Cleveland Electric Illuminating Company and its affiliates:

ATSI	American Transmission Systems, Inc., owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
CFC	Centerior Funding Corporation, a wholly owned finance subsidiary of CEI
Companies	OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec
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, an affiliated Ohio electric utility
Ohio Companies	CEI, OE and TE
Penelec	Pennsylvania Electric Company, an affiliated Pennsylvania electric utility
Penn	Pennsylvania Power Company, an affiliated Pennsylvania electric utility
Shippingport	Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
TE	The Toledo Edison Company, an affiliated Ohio electric utility
The following abbreviations and acronyms are used to identify frequently used terms in this report:
AOCL	Accumulated Other Comprehensive Loss
APB	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
CAT	Commercial Activity Tax
CO2	Carbon Dioxide
CTC	Competitive Transition Charge
ECAR	East Central Area Reliability 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
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN 46R	FASB Interpretation No. 46 (revised December 2003), "Consolidation of Variable Interest Entities"
FIN 47	FASB Interpretation 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
IRS	Internal Revenue Service
KWH	Kilowatt-hours
LOC	Lettter of Credit
Medicare Act	Medicare Prescription Drug, Improvement and Modernization Act of 2003
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service
MSG	Market Support Generation

i

GLOSSARY OF TERMS, Cont'd.

MW	Megawatts
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Council
NOAC	Northwest Ohio Aggregation Coalition
NOX	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
OCC	Ohio Consumers' Counsel
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
PJM	PJM Interconnection L. L. C.
PLR	Provider of Last Resort
PRP	Potentially Responsible Party
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act
RCP	Rate Certainty Plan
RFP	Request for Proposal
RSP	Rate Stabilization Plan
RTC	Regulatory Transition Charge
S&P	Standard & Poor’s Ratings Service
SEC	United States Securities and Exchange Commission
SFAC	Statement of Financial Accounting Concepts
SFAC 7	SFAC No. 7, "Using Cash Flow Information and Present Value in Accounting Measurements"
SFAS	Statement of Financial Accounting Standards
SFAS 71	SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
SFAS 87	SFAS No. 87, "Employers' Accounting for Pensions"
SFAS 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 140	SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities"
SFAS 142	SFAS No. 142, "Goodwill and Other Intangible Assets"
SFAS 143	SFAS No. 143, "Accounting for Asset Retirement Obligations"
SFAS 144	SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"
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

The Cleveland Electric Illuminating 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 The Cleveland Electric Illuminating 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. As discussed in Note 6 to the consolidated financial statements, the Company changed its method of accounting for the consolidation of variable interest entities as of December 31, 2003.

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.

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
SELECTED FINANCIAL DATA
	2005			2004			2003			2002			2001
	(Dollars in thousands)
GENERAL FINANCIAL INFORMATION:
Operating Revenues	$	1,868,161		$	1,808,485		$	1,719,739		$	1,843,671		$	2,064,622
Operating Income	$	308,852		$	327,909		$	255,615		$	306,152		$	354,422
Income Before Cumulative Effect
of Accounting Changes	$	231,058		$	236,531		$	197,033		$	136,962		$	177,905
Net Income	$	227,334		$	236,531		$	239,411		$	136,952		$	177,905
Earnings on Common Stock	$	224,416		$	229,523		$	231,885		$	121,262		$	153,067
Total Assets	$	6,101,670		$	6,675,377		$	6,758,501		$	6,500,238		$	6,515,968
CAPITALIZATION AS OF DECEMBER 31:
Common Stockholder’s Equity	$	1,942,074		$	1,853,561		$	1,778,827		$	1,200,001		$	1,082,041
Preferred Stock-
Not Subject to Mandatory Redemption		-			96,404			96,404			96,404			141,475
Subject to Mandatory Redemption		-			-			-			105,021			106,288
Long-Term Debt and Other Long-Term Obligations		1,939,300			1,970,117			1,884,643			1,975,001			2,156,322
Total Capitalization	$	3,881,374		$	3,920,082		$	3,759,874		$	3,376,427		$	3,486,126
CAPITALIZATION RATIOS:
Common Stockholder’s Equity		50.0	%		47.3	%		47.3	%		35.5	%		31.0	%
Preferred Stock-
Not Subject to Mandatory Redemption		-			2.5			2.6			2.9			4.1
Subject to Mandatory Redemption		-			-			-			3.1			3.0
Long-Term Debt and Other Long-Term Obligations		50.0			50.2			50.1			58.5			61.9
Total Capitalization		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%
DISTRIBUTION KWH DELIVERIES (Millions):
Residential		5,699			5,264			5,216			5,370			5,061
Commercial		4,998			4,817			4,690			4,628			4,907
Industrial		9,041			9,006			8,908			8,921			9,593
Other		172			162			169			167			166
Total		19,910			19,249			18,983			19,086			19,727
CUSTOMERS SERVED:
Residential		675,071			674,292			669,337			677,095			673,852
Commercial		85,033			81,093			80,596			71,893			70,636
Industrial		2,304			2,211			2,318			4,725			4,783
Other		295			293			286			289			292
Total		762,703			757,889			752,537			754,002			749,563
Number of Employees		949			905			949			974			1,025

2

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT’S DISCUSSION AND

ANALYSIS OF RESULTS OF OPERATIONS

AND FINANCIAL CONDITION

Forward-looking Statements. This discussion includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms "anticipate," "potential," "expect," "believe," "estimate" and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, the continued ability of our regulated utilities to collect transition and other charges or to recover increased transmission costs, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), the repeal of PUHCA and the legal and regulatory changes resulting from the implementation of the EPACT, the uncertainty of the timing and amounts of the capital expenditures (including that such amounts could be higher than anticipated) or levels of emission reductions related to the settlement agreement resolving the New Source Review litigation, adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or operating permits, fines or other enforcement actions and remedies) of governmental investigations and oversight, including by the Securities and Exchange Commission, the United States Attorney's Office, the Nuclear Regulatory Commission and the Public Utilities Commission of Ohio as disclosed in our Securities and Exchange Commission filings, the continuing availability and operation of generating units, the ability of generating units to continue to operate at, or near full capacity, our inability to accomplish or realize anticipated benefits from strategic goals (including employee workforce factors), the anticipated benefits from our voluntary pension plan contributions, our ability to improve electric commodity margins and to experience growth in the distribution business, our ability to access the public securities and other capital markets and the cost of such capital, the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the August 14, 2003 regional power outage, the risks and other factors discussed from time to time in our Securities and Exchange Commission filings, and other similar factors. Also, a credit rating should not be viewed as a recommendation to buy, sell or hold securities and may be revised or withdrawn by a rating agency at any time. We expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events, or otherwise.

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 our ownership interests in the 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 a sale at net book value. 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.

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 generation 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. We will retain a fossil generation KWH sales arrangement and the portion of expenses related to our retained leasehold interests in the Bruce Mansfield Plant. In addition, we will receive interest income from associated company notes receivable from FGCO and NGC for the transfer of our generation net assets. 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).

3

Results of Operations

Earnings on common stock in 2005 decreased to $224 million from $230 million in 2004. Earnings on common stock in 2005 included an after-tax loss of $4 million from the cumulative effect of an accounting change due to the adoption of FIN 47. The $5 million decrease in income before the cumulative effect in 2005 resulted principally from higher nuclear and other operating costs and higher fuel and purchased power costs, partially offset by higher operating revenues and other income. Increased nuclear operating costs in 2005 compared to 2004 were due to an inspection outage at Davis-Besse and two nuclear refueling outages in 2005.

Earnings on common stock in 2004 decreased to $230 million from $232 million in 2003. Earnings on common stock in 2003 included an after-tax gain of $42 million from the cumulative effect of an accounting change due to the adoption of SFAS 143. Income before the cumulative effect increased to $237 million in 2004 from $197 million in 2003. This increase resulted principally from higher operating revenues, lower nuclear operating costs and reduced interest charges. These factors were partially offset by higher fuel and purchased power costs; depreciation and amortization charges and the absence of a 2003 gain representing net proceeds from the settlement of our claim against NRG relating to the terminated sale of three of our fossil power plants (see Note 7). Operating revenues were higher in 2004 due to significant increases in sales to FES. Lower nuclear operating costs in 2004 compared with 2003, were due to reduced incremental maintenance costs associated with the Davis-Besse extended outage and the absence of nuclear outages at Beaver Valley Unit 2 and the Perry Plant in 2004. Lower net interest charges in 2004, compared with 2003, were primarily due to debt redemptions and refinancing activities.

Operating Revenues

Operating revenues increased by $60 million or 3.3% in 2005 compared with 2004. Higher revenues resulted principally from increased generation sales revenue from franchise customers of $33 million and a $33 million increase in revenues from distribution deliveries. Under the Ohio transition plan, we provided incentives to customers to encourage switching to alternative energy providers (shopping) - $7 million of additional credits were provided to customers in 2005 compared with 2004. These revenue reductions are deferred for future recovery under our transition plan and do not affect current period earnings (see Note 2(A)).

An increase in retail generation revenues to residential and commercial customers of $11 million and $5 million, respectively, in 2005 reflected higher generation KWH sales due to decreases in shopping by residential and commercial customers of 6.0 percentage points and 0.6 percentage point, respectively. A $17 million increase in the industrial sector was primarily due to higher unit prices partially offset by lower KWH sales of 0.6% which resulted from a slight increase in shopping. Wholesale sales revenue increased by $1 million due to a $26 million increase (28.5% KWH increase) in MSG sales to unaffiliated wholesale customers partially offset by a $25 million decrease in sales (5.6% KWH decrease) to FES.

Revenues from distribution throughput increased by $33 million in 2005 compared with 2004, as total distribution deliveries increased by 3.4% in 2005. The increase in revenues was primarily due to higher distribution deliveries to residential and commercial customers, in part due to warmer summer temperatures, partially offset by lower unit prices in both sectors. Industrial revenues were down slightly as lower unit prices were partially offset by higher distribution deliveries.

Operating revenues increased by $89 million or 5.2% in 2004 compared with 2003. Higher revenues resulted principally from a $136 million (44.2%) increase in wholesale sales (primarily to FES) due to increased nuclear generation available for sale which was partially offset by reduced generation sales revenue from franchise customers of $20 million. The reduction in retail generation revenues (residential - $9 million and commercial - $18 million) in 2004 reflected an increase in shopping by residential and commercial customers of 5.5 percentage points and 8.2 percentage points, respectively. Reductions in residential and commercial revenues were partially offset by an $8 million increase in industrial retail generation revenues resulting from higher KWH sales (4.6%) to industrial customers due in part to a 2.7 percentage point reduction in shopping.

Revenues from distribution throughput decreased by $14 million in 2004 compared with 2003, even though total distribution deliveries increased by 1.4% in 2004. An improving economy increased distribution deliveries to commercial and industrial customers in 2004; however, lower unit prices in all customer sectors in 2004 more than offset the effect of higher distribution deliveries to residential and industrial customers and partially offset higher sales to the commercial sector. Revenues were further reduced due to $5 million of additional shopping incentive credits to customers in 2004 compared with 2003.

4

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

Changes in KWH Sales	2005			2004
Increase (Decrease)
Electric Generation:
Retail		4.9	%		(2.6	)%
Wholesale		(2.7	)%		44.2	%
Total Electric Generation Sales		0.5	%		20.4	%
Distribution Deliveries:
Residential		8.3	%		0.9	%
Commercial		3.8	%		2.7	%
Industrial		0.4	%		1.1	%
Total Distribution Deliveries		3.4	%		1.4	%

Operating Expenses and Taxes

Total operating expenses and taxes increased by $79 million in 2005 and $17 million in 2004 from the prior year. 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	$	8		$	23
Purchased power costs		14			5
Nuclear operating costs		26			(124	)
Other operating costs		29			36
Provision for depreciation		(4	)		7
Amortization of regulatory assets		31			30
Deferral of new regulatory assets		(46	)		(24	)
General taxes		6			10
Income taxes		15			54
Total operating expenses and taxes	$	79		$	17

Higher fuel costs in 2005 compared to 2004 were primarily due to increased fossil fuel expenses associated with higher fossil generation levels. Higher purchased power costs in 2005 compared to 2004 reflected higher KWH purchases, partially offset by lower unit costs. Higher nuclear operating costs in 2005 compared with 2004, were due to the 2005 nuclear refueling and maintenance outages at the Perry Plant, the nuclear refueling outage at Beaver Valley Unit 2 (these units did not experience outages in 2004) and a scheduled 23-day mid-cycle inspection outage at the Davis-Besse nuclear plant. Higher other operating costs were primarily due to transmission expenses related to MISO Day 2 transactions that began on April 1, 2005.

Higher fuel costs in 2004 compared to 2003 resulted principally from increased nuclear generation. Higher purchased power costs in 2004 reflected increased unit costs and KWH purchased. The decrease in nuclear operating costs for 2004 compared to 2003 was due to reduced incremental costs associated with the Davis-Besse extended outage and work performed during the refueling outages at the Perry Plant and Beaver Valley Unit 2 in 2003. Other operating costs increased in 2004, in part from higher employee benefit costs.

The decrease in depreciation in 2005 compared to 2004 was primarily due to the non-nuclear intra-system generation transfer that occurred on October 24, 2005 (see Note 14). The increase in depreciation in 2004 compared to 2003 reflected a higher level of depreciable property in 2004. Higher amortization of regulatory assets in 2005 and 2004 as compared to the prior year was primarily due to increased amortization of transition regulatory assets being recovered under the RSP. Increases in the deferral of regulatory assets in 2005 from 2004 were primarily a result of higher shopping incentive deferrals ($7 million) and associated interest ($9 million), and the PUCO-approved MISO cost deferrals ($29 million) and associated interest ($1 million). Increases in the deferral of regulatory assets in 2004 from 2003 were primarily a result of higher shopping incentive deferrals ($5 million) and associated interest ($17 million).

General taxes increased $6 million in 2005 primarily due to higher property taxes. General taxes increased $10 million in 2004 primarily due to the absence in 2004 of settled property tax claims in 2003.

                   Income taxes increased $15 million in 2005 primarily due to a reserve for potential  federal  income tax audit adjustments.

5

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 impact on income taxes associated with the required adjustment to net deferred taxes for 2005 was an additional tax expense of approximately $4 million, which was partially offset by the initial phase-out of the Ohio income-based franchise tax, which reduced income taxes by approximately $5 million in 2005.

Other Income

Other income increased by $10 million in 2005, primarily due to higher realized gains on nuclear decommissioning trust investments. Other income decreased by $55 million in 2004, principally due to a $131 million pre-tax NRG settlement (see Note 7) recognized in 2003, partially offset by interest income from Shippingport, which was consolidated into CEI as of December 31, 2003.

Net Interest Charges

Net interest charges continued to trend lower, decreasing by $4 million in 2005 and by $22 million in 2004, due to our debt paydown program. Long-term debt interest was lower due to the redemptions of $2 million and refinancing of $143 million of pollution control notes during 2005.

Cumulative Effect of Accounting Changes

Results in 2005 include an after-tax charge of $4 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 $7 million (including accumulated accretion for the period from the date the liability was incurred to the date of adoption), an asset retirement cost of $2 million (recorded as part of the carrying amount of the related long-lived asset), and accumulated depreciation of $2 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 $6 million was charged to income ($4 million, net of tax) for the year ended December 31, 2005.

Upon adoption of SFAS 143 in the first quarter of 2003, we recorded an after-tax gain to net income of $42 million. The cumulative effect adjustment for unrecognized depreciation and 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 $73 million increase to income, or $42 million net of income taxes.

Preferred Stock Dividend Requirements

Preferred stock dividend requirements decreased by $4 million in 2005 from 2004 principally due to optional preferred stock redemptions of $100 million in 2005. There is no outstanding preferred stock as of December 31, 2005.

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. Thereafter, we expect to use a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

As of December 31, 2005, we had $207,000 of cash and cash equivalents, compared with $197,000 as of December 31, 2004. The major sources of changes in these balances are summarized below.

6

Cash Flows from Operating Activities

Our net cash provided from operating activities for 2005 compared with 2004 and 2003 was as follows:

Operating Cash Flows	2005			2004			2003
	(In millions)
Cash earnings (1)	$	424		$	443		$	309
Pension trust contribution(2)		(63	)		(19	)		-
Working capital and other		(213	)		(202	)		2
Net cash provided from operating activities	$	148		$	222		$	311

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

⁽²⁾ Pension trust contributions in 2005 and 2004 are net of $30 million and $13 million of income tax benefits, respectively.

Cash earnings (in the table above) are not a measure of performance calculated in accordance with GAAP. We believe that cash earnings are 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)	$	227		$	237		$	239
Non-Cash Charges (Credits):
Provision for depreciation		128			132			125
Amortization of regulatory assets		227			196			166
Deferral of new regulatory assets		(163	)		(117	)		(93	)
Nuclear fuel and capital lease amortization		26			28			18
Amortization of electric service obligation		(14	)		(18	)		(16	)
Deferred rents and lease market valuation liability		(68	)		(56	)		(78	)
Deferred income taxes and investment tax credits, net*		42			26			(9	)
Accrued compensation and retirement benefits		5			15			(1	)
Cumulative effect of accounting changes		4			-			(42	)
Tax refund related to pre-merger period		10			-			-
Cash earnings (Non-GAAP)	$	424		$	443		$	309

*Excludes $13 million of deferred tax benefits from pension contributions in 2004.

Net cash provided from operating activities decreased $74 million in 2005 compared to 2004 as a result of a $44 million increase in after-tax voluntary pension trust contributions, a $19 million decrease in cash earnings for the reasons described under "Results of Operations" and a $11 million decrease from working capital and other cash flows. The decrease from working capital and other cash flows was principally due to a decrease in cash provided from the settlement of receivables of $141 million which was partially offset by increases in cash of $65 million from reduced tax payments and $68 million of funds received in 2005 for prepaid electric service (under a three-year Energy for Education Program with the Ohio Schools Council). Net cash provided from operating activities decreased $89 million in 2004 compared to 2003 as a result of a $204 million decrease from changes from working capital and other cash flows and the $19 million after-tax voluntary pension trust contribution, in 2004, partially offset by a $134 million increase in cash earnings for the reasons described under "Results of Operations". The decrease from working capital and other cash flows was principally due to a $149 million increase in tax payments partially offset by a $55 million increase in cash from the settlement of accounts receivable.

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Cash Flows from Financing Activities

In 2005, 2004 and 2003, net cash used for financing activities was $71 million, $98 million and $198 million, respectively, primarily reflecting the new issues and redemptions shown below.

Securities Issued or Redeemed	2005		2004		2003
	(In millions)
New Issues:
Pollution Control Notes	$	141	$	125	$	-
Unsecured Notes		-		-		297
Redemptions:
FMB	$	-	$	-	$	550
Pollution Control Notes		147		46		112
Secured Notes		-		288		15
Preferred Stock		102		1		1
Other		1		1		-
	$	250	$	336	$	678
Short-term borrowings, net	$	156	$	290	$	(109	)

Net cash used for financing activities decreased by $27 million in 2005 compared to 2004. The decrease resulted from a $75 million equity contribution from FirstEnergy, partially offset by a $21 million increase in common stock dividend payments to FirstEnergy and an increase in net debt redemptions shown above.

We had $207,000 of cash and temporary investments and approximately $352 million of short-term indebtedness as of December 31, 2005. We have obtained authorization from the PUCO to incur short-term debt of up to $500 million (including through available bank facilities and the utility money pool described below). In addition, we have $200 million ($60 million unused as of December 31, 2005) of accounts receivable financing facilities from CFC, our wholly owned subsidiary. As a separate legal entity with separate creditors, CFC would have to satisfy its obligations to creditors before any of its remaining assets could be made available to us.

At the end of 2005, we had the capability to issue $111 million of additional FMB on the basis of property additions and retired bonds under the terms of our mortgage indenture following the recently completed intra-system transfer of generating assets (see Note 14). Our issuance of FMB is subject to a provision of our senior note indenture 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, this provision would permit us to incur additional secured debt not otherwise permitted by a specified exception of up to $582 million as of December 31, 2005. We have no restrictions on the issuance of preferred stock.

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

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 LOC 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 $310 million as of December 31, 2005.

The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%. As of December 31, 2005, our debt to total capitalization as defined under the revolving credit facility, was 53%.

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.

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  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 dependent on the ratings of our securities and the securities of FirstEnergy. The following table shows securities ratings as of December 31, 2005. The ratings outlook from S&P on all such 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-
CEI		Senior secured		BBB		Baa2		BBB-
		Senior unsecured		BBB-		Baa3		BB+

Cash Flows from Investing Activities

Net cash used for investing activities decreased $72 million in 2005 compared to 2004. This decrease was primarily due to increased loan activity with associated companies. The $466 million increase in collection of principal amounts on long-term notes receivable in 2005 included a $375 million repayment from NGC and $91 million from ATSI. The $375 million received from NGC related to the nuclear generation asset transfer that occurred on December 16, 2005. This increase in collection from associated companies was partially offset by $388 million in loan payments to the money pool in 2005, compared to $10 million in loan repayments from associated companies in 2004. Higher expenditures for property additions were substantially offset by increased investments in lessor notes.

Net cash used for investing activities increased $30 million in 2004 compared to 2003 and primarily reflected increased investments in lessor notes, partially offset by increased loan payments received from associated companies and lower expenditures for property additions.

Our capital spending for the period 2006-2010 is expected to be about $600 million of which approximately $107 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 assets transfers.

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)	$	2,004	$	-	$	269	$	180	$	1,555
Short-term borrowings		352		352		-		-		-
Capital leases		7		1		2		2		2
Operating leases (2)		194		19		28		24		123
Purchases (3)		343		47		100		96		100
Total	$	2,900	$	419	$	399	$	302	$	1,780

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

⁽²⁾Operating lease payments are net of capital trust receipts of $497.6 million (see Note 5).

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

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Off-Balance Sheet Arrangements

We have obligations not included on our Consolidated Balance Sheets related to sale and leaseback arrangements involving the Bruce Mansfield Plant, which is reflected in the operating lease payments above (see Note 5 - Leases). As of December 31, 2005, the present value of these operating lease commitments, net of trust investments, total $105 million.

In June 2005, the CFC receivables financing structure was renewed and restructured from an off-balance-sheet transaction to an on-balance-sheet transaction. Under the new structure, any borrowings under the facility appear on our Consolidated Balance Sheets as short-term debt.

Interest Rate Risk

Our exposure to fluctuations in market interest rates is reduced since a significant portion of our debt has fixed interest rates. The table below 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	$		44		$	36		$	38		$	40		$	52		$	1,415		$	1,625		$	1,678
Average interest rate			7.8	%		7.7	%		7.7	%		7.7	%		7.7	%		6.4	%		6.6%
Liabilities
Long-term Debt and Other
Long-Term Obligations:
Fixed rate					$	129		$	140		$	162		$	18		$	1,044		$	1,493		$	1,645
Average interest rate						7.2	%		7.0	%		7.5	%		7.7	%		6.9	%		7.0	%
Variable rate																	$	511		$	511		$	511
Average interest rate																		3.4	%		3.4	%
Short-term Borrowings		$	352																	$	352		$	352
Average interest rate			4.2	%																	4.2	%

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

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:

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• Maintain our existing level of base distribution rates through April 30, 2009,

• 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, 2010,

• Reduce our deferred shopping incentive balances as of January 1, 2006 by up to $85 million by accelerating the application of our accumulated cost of removal regulatory liability; and

• Defer and capitalize all of our allowable fuel cost increases until January 1, 2009.

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 2010:

Amortization
Period	Amortization
	(In millions)
2006	$	100
2007		111
2008		129
2009		216
2010		268
Total Amortization	$	824

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, we filed a Motion for Clarification of the PUCO order approving the RCP. We 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. We 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, our previous requests and clarifying issues referred to above. The PUCO granted our 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 our 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 our Motion. On February 3, 2006, several other parties filed applications for rehearing on the PUCO's January 4, 2006 Order. We 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 $24 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.

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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.

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.

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.

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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.

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 its website at www.firstenergycorp.com/environmental.

Regulation of Hazardous Waste

We have been named a PRP at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of December 31, 2005, based on estimates of the total costs of cleanup, our proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Included in Other Noncurrent Liabilities are accrued liabilities aggregating approximately $1.7 million as of December 31, 2005.

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

Power Outage 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.

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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 CEI, OE, TE and Penn 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. The transfer consisted of our prior interests in Beaver Valley Unit 2 (24.47%), Davis-Besse (51.38%) and Perry (44.85%).

On January 20, 2006, FENOC announced that it has entered into a deferred prosecution agreement with the U.S. Attorney’s Office for the Northern District of Ohio and the Environmental Crimes Section of the Environment and Natural Resources Division of the DOJ related to FENOC’s communications with the NRC during the fall of 2001 in connection with the reactor head issue at the Davis-Besse Nuclear Power Station. Under the agreement, which expires on December 31, 2006, the United States acknowledged FENOC’s extensive corrective actions at Davis-Besse, FENOC’s cooperation during investigations by the DOJ and the NRC, FENOC’s pledge of continued cooperation in any related criminal and administrative investigations and proceedings, FENOC’s acknowledgement of responsibility for the behavior of its employees, and its agreement to pay a monetary penalty. The DOJ will refrain from seeking an indictment or otherwise initiating criminal prosecution of FENOC for all conduct related to the statement of facts attached to the deferred prosecution agreement, as long as FENOC remains in compliance with the agreement, which FENOC fully intends to do. FENOC has agreed to pay a penalty of $28 million (which is not deductible for income tax purposes) which reduced FirstEnergy's earnings by $0.09 per common share in the fourth quarter of 2005. As part of the deferred prosecution agreement entered into with the DOJ, $4.35 million of that amount will be directed to community service projects.

On April 21, 2005, the NRC issued a NOV and proposed a $5 million civil penalty related to the degradation of the Davis-Besse reactor vessel head issue described above. We accrued $1.0 million for a potential fine prior to 2005 and accrued the remaining liability for our share of the proposed fine of $1.8 million during the first quarter of 2005. On September 14, 2005, FENOC filed its response to the NOV with the NRC. FENOC accepted full responsibility for the past failure to properly implement its boric acid corrosion control and corrective action programs. The NRC NOV indicated that the violations do not represent current licensee performance. We paid the penalty in the third quarter of 2005.  On January 23, 2006, FENOC supplemented its response to the NRC's NOV on the Davis-Besse head degradation to reflect the deferred prosecution agreement that FENOC had reached with the DOJ.

Effective July 1, 2005 the NRC oversight panel for Davis-Besse was terminated and Davis-Besse returned to the standard NRC reactor oversight process. At that time, NRC inspections were augmented to include inspections to support the NRC's Confirmatory Order dated March 8, 2004 that was issued at the time of startup and to address an NRC White Finding related to the performance of the emergency sirens. By letter dated December 8, 2005, the NRC advised FENOC that the White Finding had been closed.

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.

14

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-

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

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.

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 our 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.

15

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.

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

In selecting an assumed discount rate, we consider currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to recent declines in corporate bond yields and interest rates in general, we reduced the assumed discount rate as of December 31, 2005 to 5.75% from 6.00% and 6.25% used as of December 31, 2004 and 2003, respectively.

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

In the fourth quarter of 2005, FirstEnergy made a $500 million voluntary contribution to its pension plan (our share was $93 million). As a result of our voluntary contribution and the increased market value of pension plan assets, we recognized a prepaid benefit cost of $139 million as of December 31, 2005. As prescribed by SFAS 87, we eliminated our additional minimum liability of $51 million and its intangible asset of $14 million. In addition, the entire AOCL balance was credited by $22 million (net of $15 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 continue to increase and will affect future OPEB costs. The 2005 and 2004 composite health care trend rate assumptions are approximately 9-11%, gradually decreasing to 5% in later years. In determining our trend rate assumptions, we included the specific provisions of our health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in our health care plans, and projections of future medical trend rates. The effect on CEI's portion of pension and OPEB costs from changes in key assumptions are as follows:

Increase in Costs from Adverse Changes in Key Assumptions
Assumption	Adverse Change		Pension		OPEB		Total
			(In millions)
Discount rate		Decrease by 0.25%	$	0.7	$	0.3	$	1.0
Long-term return on assets		Decrease by 0.25%	$	0.7	$	-	$	0.7
Health care trend rate		Increase by 1%		na	$	2.3	$	2.3

16

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).

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

Goodwill

In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, we evaluate our goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If an impairment were indicated, we recognize a loss - calculated as the difference between the implied fair value of our goodwill and the carrying value of the goodwill. Our annual review was completed in the third quarter of 2005, with no impairment of goodwill indicated. The forecasts used in our evaluation of goodwill reflect operations consistent with our general business assumptions. Unanticipated changes in those assumptions could have a significant effect on our future evaluations of goodwill. In the year ended December 31, 2005, we adjusted goodwill to reverse pre-merger tax accruals due to the final resolution of tax contingencies related to the Centerior acquisition. As of December 31, 2005, we had approximately $1.7 billion of goodwill.

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 and any impact on our investments.

17

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.

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 beginning January 1, 2006. We do not expect this statement to have a material impact on the financial statements.

18

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2005			2004			2003
				(In thousands)
OPERATING REVENUES (Note 2(I))	$	1,868,161		$	1,808,485		$	1,719,739
OPERATING EXPENSES AND TAXES:
Fuel		85,993			78,072			55,031
Purchased power (Note 2(I))		557,593			543,949			538,785
Nuclear operating costs		142,698			117,091			240,971
Other operating costs (Note 2(I))		301,366			272,303			236,359
Provision for depreciation		127,959			131,854			125,467
Amortization of regulatory assets		227,221			196,501			166,343
Deferral of new regulatory assets		(163,245	)		(117,466	)		(93,503	)
General taxes		152,678			146,276			136,434
Income taxes		127,046			111,996			58,237
Total operating expenses and taxes		1,559,309			1,480,576			1,464,124
OPERATING INCOME		308,852			327,909			255,615
OTHER INCOME (net of income taxes) (Notes 2(I) and 7)		51,899			42,190			97,318
NET INTEREST CHARGES:
Interest on long-term debt		110,419			120,058			157,967
Allowance for borrowed funds used during construction		(2,533	)		(5,110	)		(8,232	)
Other interest expense		21,807			18,620			1,665
Subsidiary's preferred stock dividend requirements		-			-			4,500
Net interest charges		129,693			133,568			155,900
INCOME BEFORE CUMULATIVE EFFECT
OF ACCOUNTING CHANGES		231,058			236,531			197,033
Cumulative effect of accounting changes (net of income taxes
(benefit) of ($2,101,000) and $30,168,000, respectively) (Note 2(G))		(3,724	)		-			42,378
NET INCOME		227,334			236,531			239,411
PREFERRED STOCK DIVIDEND REQUIREMENTS		2,918			7,008			7,526
EARNINGS ON COMMON STOCK	$	224,416		$	229,523		$	231,885
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

19

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31,	2005		2004
	(In thousands)
ASSETS
UTILITY PLANT:
In service	$	2,030,935	$	4,418,313
Less - Accumulated provision for depreciation		788,967		1,961,737
		1,241,968		2,456,576
Construction work in progress-
Electric plant		51,129		85,258
Nuclear fuel		-		30,827
		51,129		116,085
		1,293,097		2,572,661
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes (Note 6)		564,166		596,645
Nuclear plant decommissioning trusts		-		383,875
Long-term notes receivable from associated companies		1,076,715		97,489
Other		12,840		17,001
		1,653,721		1,095,010
CURRENT ASSETS:
Cash and cash equivalents		207		197
Receivables-
Customers (less accumulated provision of $5,180,000 for uncollectible accounts in 2005)		268,427		11,537
Associated companies		86,564		33,414
Other		16,466		152,785
Notes receivable from associated companies		-		521
Materials and supplies, at average cost		-		58,922
Prepayments and other		1,903		2,136
		373,567		259,512
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		1,688,966		1,693,629
Regulatory assets		862,193		943,898
Prepaid pension costs		139,012		-
Property taxes		63,500		77,792
Other		27,614		32,875
		2,781,285		2,748,194
	$	6,101,670	$	6,675,377
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity	$	1,942,074	$	1,853,561
Preferred stock		-		96,404
Long-term debt and other long-term obligations		1,939,300		1,970,117
		3,881,374		3,920,082
CURRENT LIABILITIES:
Currently payable long-term debt		75,718		76,701
Short-term borrowings-
Associated companies		212,256		488,633
Other		140,000		-
Accounts payable-
Associated companies		74,993		150,141
Other		4,664		9,271
Accrued taxes		121,487		129,454
Accrued interest		18,886		22,102
Lease market valuation liability		60,200		60,200
Other		61,308		61,131
		769,512		997,633
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		554,828		540,211
Accumulated deferred investment tax credits		23,908		60,901
Lease market valuation liability		608,000		668,200
Asset retirement obligation		8,024		272,123
Retirement benefits		83,414		82,306
Deferred revenues - electric service programs		71,261		17,814
Other		101,349		116,107
		1,450,784		1,757,662
COMMITMENTS AND CONTINGENCIES (Notes 5 and 13)
	$	6,101,670	$	6,675,377
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.

20

THE CLEVELAND ELECTRIC ILLUMINATING 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 105,000,000 shares							$	1,354,924		$	1,281,962
79,590,689 shares outstanding
Accumulated other comprehensive income (Note 2(F))								-			17,859
Retained earnings (Note 10(A))								587,150			553,740
Total common stockholder's equity								1,942,074			1,853,561
	Number of Shares Outstanding			Optional  Redemption Price
		2005	2004	Per Share		Aggregate
PREFERRED STOCK NOT SUBJECT TO
MANDATORY REDEMPTION (Note 10(B)):
Cumulative, without par value-
Authorized 4,000,000 shares
$ 7.40 Series A		-	500,000		$	-		-			50,000
Adjustable Series L		-	474,000			-		-			46,404
Total		-	974,000		$	-		-			96,404
LONG-TERM DEBT AND OTHER
LONG-TERM OBLIGATIONS (Note 10(C)):
First mortgage bonds:
6.860% due 2008								125,000			125,000
Total first mortgage bonds								125,000			125,000
Secured notes:
7.000% due 2005-2009								-			1,700
7.130% due 2007								120,000			120,000
7.430% due 2009								150,000			150,000
*  3.150% due 2015								39,835			39,835
7.880% due 2017								300,000			300,000
*  3.150% due 2018								72,795			72,795
*  3.580% due 2020								47,500			47,500
6.000% due 2020								62,560			62,560
6.100% due 2020								70,500			70,500
7.625% due 2025								-			53,900
7.700% due 2025								-			43,800
7.750% due 2025								-			45,150
5.375% due 2028								5,993			5,993
*  3.350% due 2030								23,255			23,255
*  3.750% due 2030								81,640			81,640
*  3.150% due 2033								30,000			30,000
*  3.150% due 2033								46,100			46,100
*  3.050% due 2034								40,900			-
*  3.500% due 2034								2,900			-
*  3.350% due 2035								53,900			-
*  3.500% due 2035								45,150			-
Total secured notes								1,193,028			1,194,728
Unsecured notes:
6.000% due 2013								78,700			78,700
5.650% due 2013								300,000			300,000
9.000% due 2031								103,093			103,093
*  3.670% due 2033								27,700			27,700
								509,493			509,493
7.742% due to associated companies 2007-2016 (Note 6)								176,847			188,629
Total unsecured notes								686,340			698,122
Preferred stock subject to mandatory redemption								-			4,009
Capital lease obligations (Note 5)								4,939			5,455
Net unamortized premium on debt								5,711			19,504
Long-term debt due within one year								(75,718	)		(76,701	)
Total long-term debt and other long-term obligations								1,939,300			1,970,117
TOTAL CAPITALIZATION							$	3,881,374		$	3,920,082
* Denotes variable rate issue with December 31, 2005 interest rate shown.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

21

THE CLEVELAND ELECTRIC ILLUMINATING 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					79,590,689	$	981,962		$	(44,284	)	$	262,323
Net income	$	239,411											239,411
Unrealized gain on investments, net of
$19,598,000 of income taxes		28,255								28,255
Minimum liability for unfunded retirement benefits,
net of $13,760,000 of income taxes		18,682								18,682
Comprehensive income	$	286,348
Equity contribution from parent							300,000
Cash dividends on preferred stock													(7,429	)
Preferred stock redemption premiums													(93	)
Balance, December 31, 2003					79,590,689		1,281,962			2,653			494,212
Net income	$	236,531											236,531
Unrealized gain on investments, net of
$8,294,000 of income taxes		11,450								11,450
Minimum liability for unfunded retirement benefits,
net of $2,413,000 of income taxes		3,756								3,756
Comprehensive income	$	251,737
Cash dividends on preferred stock													(7,003	)
Cash dividends on common stock													(170,000	)
Balance, December 31, 2004					79,590,689		1,281,962			17,859			553,740
Net income	$	227,334											227,334
Unrealized loss on investments, net of
$(27,734,000) of income taxes		(39,472	)							(39,472	)
Minimum liability for unfunded retirement benefits,
net of $15,186,000 of income taxes		21,613								21,613
Comprehensive income	$	209,475
Equity contribution from parent							75,000
Affiliated company asset transfers							(2,086	)
Restricted stock units							48
Cash dividends on preferred stock													(2,924	)
Cash dividends on common stock													(191,000	)
Balance, December 31, 2005					79,590,689	$	1,354,924		$	-		$	587,150

CONSOLIDATED STATEMENTS OF PREFERRED STOCK
	Not Subject to						Subject to
	Mandatory Redemption						Mandatory Redemption*
	Number			Carrying			Number			Carrying
	of Shares			Value			of Shares			Value
	(Dollars in thousands)
Balance, January 1, 2003		974,000		$	96,404			4,060,000		$	106,021
Redemptions-
$7.35 Series C								(10,000	)		(1,000	)
FIN 46 Deconsolidation-
9.00% Series								(4,000,000	)		(100,000	)
Amortization of fair market
value adjustments-
$7.35 Series C											(7	)
Balance, December 31, 2003		974,000			96,404			50,000			5,014
Redemptions-
$7.35 Series C								(10,000	)		(1,000	)
Amortization of fair market
value adjustments-
$7.35 Series C											(5	)
Balance, December 31, 2004		974,000			96,404			40,000			4,009
Redemptions-
$7.40 Series A		(500,000	)		(50,000	)
Adjustable Series L		(474,000	)		(46,404	)
$7.35 Series C								(40,000	)		(4,000	)
Amortization of fair market
value adjustments-
$7.35 Series C											(9	)
Balance, December 31, 2005		-		$	-			-		$	-
* 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.

22

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,	2005			2004			2003
				(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	227,334		$	236,531		$	239,411
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation		127,959			131,854			125,467
Amortization of regulatory assets		227,221			196,501			166,343
Deferral of new regulatory assets		(163,245	)		(117,466	)		(93,503	)
Nuclear fuel and capital lease amortization		25,803			28,239			17,466
Deferred rents and lease market valuation liability		(67,353	)		(56,405	)		(78,214	)
Deferred income taxes and investment tax credits, net		42,024			39,129			(7,836	)
Accrued compensation and retirement benefits		4,624			15,678			(1,113	)
Cumulative effect of accounting changes		3,724			-			(42,378	)
Pension trust contribution		(93,269	)		(31,718	)		-
Tax refund related to pre-merger period		9,636			-			-
Decrease (increase) in operating assets-
Receivables		(103,018	)		38,297			(16,339	)
Materials and supplies		(12,934	)		(8,306	)		5,771
Prepayments and other current assets		233			2,375			(294	)
Increase (decrease) in operating liabilities-
Accounts payable		(82,434	)		(93,745	)		(54,858	)
Accrued taxes		(7,967	)		(73,068	)		76,261
Accrued interest		(3,216	)		(15,770	)		(13,895	)
Electric service prepayment programs		53,447			(18,386	)		(16,278	)
Other		(40,878	)		(51,617	)		4,754
Net cash provided from operating activities		147,691			222,123			310,765
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		141,004			124,977			296,905
Short-term borrowings, net		155,883			290,263			-
Equity contributions from parent		75,000			-			300,000
Redemptions and Repayments-
Preferred stock		(101,900	)		(1,000	)		(1,093	)
Long-term debt		(147,923	)		(335,393	)		(677,097	)
Short-term borrowings, net		-			-			(109,212	)
Dividend Payments-
Common stock		(191,000	)		(170,000	)		-
Preferred stock		(2,260	)		(7,008	)		(7,451	)
Net cash used for financing activities		(71,196	)		(98,161	)		(197,948	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(148,783	)		(121,316	)		(134,899	)
Loan repayments from (loans to) associated companies, net		(387,746	)		9,936			(5,450	)
Collection of principal on long-term notes receivable		466,378			482			447
Investments in lessor notes		32,479			9,270			44,732
Contributions to nuclear decommissioning trusts		(29,024	)		(29,024	)		(29,024	)
Other		(9,789	)		(17,895	)		5,777
Net cash used for investing activities		(76,485	)		(148,547	)		(118,417	)
Net increase (decrease) in cash and cash equivalents		10			(24,585	)		(5,600	)
Cash and cash equivalents at beginning of year		197			24,782			30,382
Cash and cash equivalents at end of year	$	207		$	197		$	24,782
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	144,730		$	152,373		$	174,375
Income taxes	$	116,323		$	144,277		$	24,796
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

23

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF TAXES
For the Years Ended December 31,	2005			2004			2003
	(In thousands)
GENERAL TAXES:
Real and personal property	$	77,822		$	74,206		$	63,448
Ohio kilowatt-hour excise*		68,950			66,974			68,459
Social security and unemployment		5,282			4,496			4,331
Other		624			600			196
Total general taxes	$	152,678		$	146,276		$	136,434
PROVISION FOR INCOME TAXES:
Currently payable-
Federal	$	88,147		$	72,264		$	109,775
State		22,843			27,463			29,346
		110,990			99,727			139,121
Deferred, net-
Federal		28,310			34,450			21,382
State		16,350			9,775			5,757
		44,660			44,225			27,139
Investment tax credit amortization		(4,737	)		(5,096	)		(4,807	)
Total provision for income taxes	$	150,913		$	138,856		$	161,453
INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income	$	127,046		$	111,996		$	58,237
Other income		25,968			26,860			73,048
Cumulative effect of accounting changes		(2,101	)		-			30,168
Total provision for income taxes	$	150,913		$	138,856		$	161,453
RECONCILIATION OF FEDERAL INCOME TAX
EXPENSE AT STATUTORY RATE TO TOTAL
PROVISION FOR INCOME TAXES:
Book income before provision for income taxes	$	378,247		$	375,387		$	400,864
Federal income tax expense at statutory rate	$	132,387		$	131,385		$	140,302
Increases (reductions) in taxes resulting from-
State income taxes, net of federal income tax benefit		25,475			24,205			22,817
Amortization of investment tax credits		(4,737	)		(5,096	)		(4,807	)
Other, net		(2,212	)		(11,638	)		3,141
Total provision for income taxes	$	150,913		$	138,856		$	161,453
ACCUMULATED DEFERRED INCOME TAXES AS OF
DECEMBER 31:
Property basis differences	$	498,079		$	502,625		$	477,358
Regulatory transition charge		159,535			221,386			302,270
Asset retirement obligations		-			24,638			23,086
Unamortized investment tax credits		(10,150	)		(23,208	)		(25,311	)
Deferred gain for asset sales- affiliated companies		33,329			33,841			38,394
Other comprehensive income		-			12,548			1,841
Above market leases		(256,297	)		(300,000	)		(324,843	)
Retirement benefits		12,005			(21,674	)		(32,023	)
Shopping incentive deferral		153,750			121,778			73,804
Other		(35,423	)		(31,723	)		(48,528	)
Net deferred income tax liability	$	554,828		$	540,211		$	486,048
*  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.

24

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.ORGANIZATION AND BASIS OF PRESENTATION:

The consolidated financial statements include CEI (Company) and its wholly owned subsidiaries, CFC and Shippingport (see Note 6). The Company is a wholly owned subsidiary of FirstEnergy. FirstEnergy also holds directly all of the issued and outstanding common shares of its other principal electric utility operating subsidiaries, including OE, TE, ATSI, JCP&L, Met-Ed and Penelec. In the fourth quarter of 2005, the Company completed the intra-system transfers of its non-nuclear and nuclear generation assets to FGCO and NGC, respectively. See Note 14 - FirstEnergy Intra-System Generation Asset Transfers for further discussion.

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

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

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

2.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

(A)ACCOUNTING FOR THE EFFECTS OF REGULATION-

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

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

·are cost-based; and

·can be charged to and collected from customers.

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

Regulatory Assets-

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

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

	2005			2004
	(In millions)
Regulatory transition costs	$	479		$	705
Customer shopping incentives		427			295
Employee postretirement benefit costs		12			13
Asset removal costs		(90	)		(75	)
MISO transmission costs		30			-
Other		4			6
Total	$	862		$	944

25

The Company has been deferring customer shopping incentives and interest costs (Extended RTC) as new regulatory assets in accordance with the prior transition and rate stabilization plans. As a result of the RCP approved in January 2006, the Extended RTC balance ($427 million as of December 31, 2005) was reduced on January 1, 2006 by $85 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. The Company's recovery of its RTC is projected to be completed by April 2009 at which time recovery of its Extended RTC will begin, with recovery estimated to be completed as of December 31, 2010. 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 2010:

Amortization
Period	Amortization
	(In millions)
2006	$	100
2007		111
2008		129
2009		216
2010		268
Total Amortization	$	824

(B)CASH AND SHORT-TERM FINANCIAL INSTRUMENTS-

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

(C)REVENUES AND RECEIVABLES-

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

Receivables from customers include sales to residential, commercial and industrial customers located in the Company's service area and sales to wholesale customers. There was no material concentration of receivables as of December 31, 2005, with respect to any particular segment of the Company's customers. Total customer receivables were $268 million (billed - $157 million and unbilled - $111 million) and $12 million (billed - $9 million and unbilled - $3 million) as of December 31, 2005 and 2004, respectively.

The Company and TE sell substantially all of their retail customer receivables to CFC. In June 2005, the CFC receivables financing structure was renewed and restructured from an off-balance sheet transition to an on-balance sheet transaction. Under the new structure, any borrowings under the facility appear on the balance sheet as short-term debt.

(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 Company's accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred.

26

The Company provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annualized composite rate was approximately 2.9% in 2005, 2.8% in 2004, and 2.8% in 2003.

(E)ASSET IMPAIRMENTS-

Long-Lived Assets-

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

Goodwill-

In a business combination, the excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, the Company evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If an impairment is indicated, the Company recognizes a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. The Company's 2005 annual review was completed in the third quarter of 2005 with no impairment indicated. The forecasts used in the Company's evaluation of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on its future evaluations of goodwill. As of December 31, 2005, the Company had approximately $1.7 billion of goodwill. In the year ended December 31, 2005, the Company adjusted goodwill to reverse pre-merger tax accruals due to the final resolution of tax contingencies related to the Centerior acquisition. The impairment analysis includes a significant source of cash representing the Company's recovery of transition costs as described below under "Regulatory Matters." The Company estimates that completion of transition cost recovery will not result in an impairment of goodwill.

(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, the Company does not have an accumulated other comprehensive balance. As of December 31, 2004, accumulated other comprehensive income consisted of a minimum liability for unfunded retirement benefits of $22 million and unrealized gains on investments in securities available for sale of $40 million.

(G)CUMULATIVE EFFECT OF ACCOUNTING CHANGES-

Results in 2005 include an after-tax charge of $4 million recorded upon the adoption of FIN 47 in December 2005. The Company identified applicable legal obligations as defined under the new standard at its retired generating units, substation control rooms, service center buildings, line shops and office buildings, identifying asbestos as the primary conditional ARO. The Company recorded a conditional ARO liability of $7 million (including accumulated accretion for the period from the date the liability was incurred to the date of adoption), an asset retirement cost of $2 million (recorded as part of the carrying amount of the related long-lived asset), and accumulated depreciation of $2 million. The Company charged a regulatory liability 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 $6 million was charged to income ($4 million, net of tax).

Results for 2003 include an after-tax credit to net income of $42 million recorded by the Company upon adoption of SFAS 143 in January of 2003. The Company identified applicable legal obligations as defined under the new accounting standard for nuclear power plant decommissioning, reclamation of a sludge disposal pond at the Bruce Mansfield Plant, and closure of two coal ash disposal sites. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $50 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $7 million. The asset retirement obligation liability at the date of adoption was $238 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, the Company had recorded decommissioning liabilities of $243 million. The cumulative effect adjustment for unrecognized depreciation and accretion, offset by the reduction in the existing decommissioning liabilities and the reversal of accumulated estimated removal costs for non-regulated generation assets, was a $73 million increase to income, or $42 million net of income taxes.

27

(H)INCOME TAXES-

Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. The Company records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled. The Company is included in FirstEnergy's consolidated federal income tax return. The consolidated tax liability is allocated on a "stand-alone" company basis, with each Company recognizing any tax losses or credits the Company contributes 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 Company, TE, OE and Penn. As a result, the Company had entered into power supply agreements (PSA) whereby FES purchased all of the Company's nuclear generation and the generation from leased fossil generation facilities. In the fourth quarter of 2005, the Company, TE, OE and Penn 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 rent revenues 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 Company's transfers. The Company is now receiving interest income from FGCO and NGC on the associated companies notes received in exchange for the transferred net assets. The Company continues to purchase its power from FES to meet its 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. CFC serves as the transferor in connection with the accounts receivable securitization for the Company and TE. The primary affiliated company's transactions are as follows:

	2005		2004		2003
	(In millions)
Operating Revenues:
PSA revenues from FES	$	362	$	387	$	260
Generating units rent from FES		49		59		59
Ground lease with ATSI		7		7		7
Services Received:
Purchased power under PSA		452		444		423
Purchased power from TE		105		101		109
Transmission expenses		-		-		32
FESC support services		60		65		63
Other Income:
Interest income from ATSI		1		7		7
Interest income from FES and NGC		6		-		1

The Company is buying 150 MW of TE's Beaver Valley Unit 2 leased capacity entitlement. Purchased power expenses for this transaction were $105 million, $101 million and $109 million in 2005, 2004 and 2003, respectively. This purchase agreement is expected to continue through the end of the lease period (see Note 5).

FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Company from FESC, a subsidiary of FirstEnergy. 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.

28

3.PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS:

FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees. The trustee plans provide defined benefits based on years of service and compensation levels. The Company's funding policy is based on actuarial computations using the projected unit credit method. In the fourth quarter of 2005, FirstEnergy made a $500 million voluntary contribution to its pension plan (Company's share was $93 million). Projections indicated that absent this funding, cash contributions would have been required at some point prior to 2010. Pre-funding the pension plan is expected to eliminate this future funding requirement under current pension funding rules and should also minimize FirstEnergy's exposure to any funding requirements resulting from proposed pension reform.

FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. The Company recognizes the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement for disability related benefits.

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

29

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	)
Company's share of net amount recognized	$	139		$	47		$	(83	)	$	(77	)
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

30

	Pension Benefits									Other Benefits
Components of Net Periodic Benefit Costs	2005			2004			2003			2005			2004			2003
	(In millions)
Service cost	$	77		$	77		$	66		$	40		$	36		$	43
Interest cost		254			252			253			111			112			137
Expected return on plan assets		(345	)		(286	)		(248	)		(45	)		(44	)		(43	)
Amortization of prior service cost		8			9			9			(45	)		(40	)		(9	)
Amortization of transition obligation		-			-			-			-			-			9
Recognized net actuarial loss		36			39			62			40			39			40
Net periodic cost	$	30		$	91		$	142		$	101		$	103		$	177
Company's share of net periodic cost	$	1		$	6		$	10		$	15		$	18		$	15

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

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

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 Company recognized a prepaid pension cost of $139 as of December 31, 2005. As prescribed by SFAS 87, the Company eliminated its additional minimum liability of $51 million and its intangible asset of $14 million. In addition, the entire AOCL balance was credited by $22 million (net of $15 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.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	$	1,901	$	2,016	$	1,915	$	2,079
Subordinated debentures to affiliated trusts		103		140		103		112
Preferred stock subject to mandatory redemption		-		-		4		4
	$	2,004	$	2,156	$	2,022	$	2,195

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 Company's 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	$	-	$	-	$	100	$	100
-Corporate debt securities(2)		1,625		1,678		734		854
		1,625		1,678		834		954
Equity securities(1)		-		-		242		242
	$	1,625	$	1,678	$	1,076	$	1,196

⁽¹⁾Includes nuclear decommissioning trust investments as of December 31, 2004.

⁽²⁾Includes investments in lease obligation bonds (see Note 5).

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. Prior to their transfer to NGC (see Note 11), the Company's decommissioning trust investments were classified as available-for-sale. The Company has no securities held for trading purposes.

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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	$	475	$	411	$	226
Gross realized gains		49		35		15
Gross realized losses		20		21		16
Interest and dividend income		12		11		9

Prior to their transfer to NGC, unrealized gains and losses applicable to the Company's decommissioning trusts were recognized in OCI in accordance with SFAS 115.

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

5.LEASES:

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

The Company and TE sold their ownership interests in Bruce Mansfield Units 1, 2 and 3 and TE sold a portion of its ownership interest in Beaver Valley Unit 2. In connection with these sales, which were completed in 1987, the Company and TE entered into operating leases for lease terms of approximately 30 years as co-lessees. During the terms of the leases, the Company and TE continue to be responsible, to the extent of their leasehold interest, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. The Company and TE have the right, at the end of the respective basic lease terms, to renew the leases. The Company and TE also have 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.

As co-lessee with TE, the Company is also obligated for TE's lease payments. If TE is unable to make its payments under the Beaver Valley Unit 2 and Bruce Mansfield Plant leases, the Company would be obligated to make such payments. No such payments have been made on behalf of TE. (TE's future minimum lease payments as of December 31, 2005 were approximately $0.8 billion, net of trust cash receipts.)

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	$	28.4	$	29.1	$	31.9
Other		40.9		29.4		48.0
Capital leases
Interest element		0.5		0.5		0.6
Other		0.5		0.5		0.4
Total rentals	$	70.3	$	59.5	$	80.9

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

				Operating Leases
	Capital			Lease		Capital
	Leases			Payments		Trust		Net
	(In millions)
2006	$	1.0		$	75.2	$	56.2	$	19.0
2007		1.0			61.7		48.2		13.5
2008		1.0			57.8		42.9		14.9
2009		1.0			59.6		46.1		13.5
2010		1.0			59.9		49.0		10.9
Years thereafter		1.6			377.9		255.2		122.7
Total minimum lease payments		6.6		$	692.1	$	497.6	$	194.5
Interest portion		(1.7	)
Present value of net minimum lease payments		4.9
Less current portion		(0.5	)
Noncurrent portion	$	4.4

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The Company has recorded above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant associated with the 1997 merger creating FirstEnergy. The total above-market lease obligation of $611 million associated with Beaver Valley Unit 2 is being amortized on a straight-line basis through the end of the lease term in 2017 (approximately $31 million per year). The total above-market lease obligation of $457 million associated with the Bruce Mansfield Plant is being amortized on a straight-line basis through the end of 2016 (approximately $29 million per year). As of December 31, 2005 the above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant totaled approximately $668 million, of which $60 million is payable within one year.

The Company and TE refinanced high-cost fixed obligations related to their 1987 sale and leaseback transaction for the Bruce Mansfield Plant through a lower cost transaction in June and July 1997. In a June 1997 offering, the two companies pledged $720 million aggregate principal amount ($575 million for the Company and $145 million for TE) of FMB due through 2007 to a trust as security for the issuance of a like principal amount of secured notes due through 2007. The obligations of the two companies under these secured notes are joint and several. Using available cash, short-term borrowings and the net proceeds from the offering, the two companies invested $907 million ($569 million for the Company and $337 million for TE) in a business trust, in June 1997. The trust used these funds in July 1997 to purchase lease notes and redeem all $873 million aggregate principal amount of 10-1/4% and 11-1/8% secured lease obligation bonds (SLOBs) due 2003 and 2016. The SLOBs were issued by a special-purpose-funding corporation in 1988 on behalf of lessors in the two companies' 1987 sale and leaseback transactions. The Shippingport arrangement effectively reduces lease costs related to that transaction.

6.VARIABLE INTEREST ENTITIES:

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

Included in the Company's consolidated financial statements is Shippingport, a VIE created in 1997, to refinance debt originally issued in connection with the Bruce Mansfield Plant sale and leaseback transaction.

Shippingport was established to purchase all of the SLOBs issued in connection with the Company's and TE's Bruce Mansfield Plant sale and leaseback transaction in 1987. The Company and TE used debt and available funds to purchase the notes issued by Shippingport. Shippingport's note payable to TE of $189 million ($12 million current) and $199 million ($10 million current) as of December 31, 2005 and December 31, 2004, respectively, is included in long-term debt on the Company's Consolidated Balance Sheets.

Through its investment in Shippingport, the Company has a variable interest in certain owner trusts that acquired the interests in the Bruce Mansfield Plant. 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 $105 million, that would not be payable if the casualty value payments are made.

7.SALE OF GENERATING ASSETS:

In August 2002, FirstEnergy cancelled a November 2001 agreement to sell four coal-fired power plants (2,535 MW) to NRG Energy Inc. because NRG stated that it could not complete the transaction under the original terms of the agreement. NRG filed voluntary bankruptcy petitions in May 2003; subsequently, FirstEnergy reached an agreement for settlement of its claim against NRG. FirstEnergy sold its entire claim (including $32 million of cash proceeds received in December 2003) for $170 million (Company's share - $131 million).

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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 impact on income taxes associated with the required adjustment to net deferred taxes for 2005 was an additional tax expense of approximately $4 million, which was partially offset by the initial phase-out of the Ohio income-based franchise tax, which reduced income taxes by approximately $5 million in 2005.

9.REGULATORY MATTERS:

Regulatory assets are costs which have been authorized by the PUCO 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.

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

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

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

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

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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.

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.

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.

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 April 30, 2009 for CEI;

· 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, 2010 for CEI;

· Reduce the deferred shopping incentive balances as of January 1, 2006 by up to $85 million for CEI by accelerating the application of its accumulated cost of removal regulatory liability; and

· Defer and capitalize all of CEI's allowable fuel cost increases until January 1, 2009.

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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 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 $24 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.

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.

10.CAPITALIZATION:

(A)RETAINED EARNINGS-

There are no restrictions on retained earnings for payment of cash dividends on the Company’s common stock.

(B)PREFERRED AND PREFERENCE STOCK-

No preferred stock shares are currently outstanding.

The preferred dividend rate on the Company’s Series L fluctuated based on prevailing interest rates and market conditions. The dividend rate for this issue was 7% in 2005.

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

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

The Company 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 has various debt covenants under its financing arrangements. The most restrictive of the 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 covenants. There also exist cross-default provisions among financing agreements of FirstEnergy and the Company.

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

	(In millions)
2006	$	75
2007		129
2008		221
2009		162
2010		18

Included in the table above are amounts for various variable interest rate long-term debts 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 $75 million and $82 million in 2006 and 2008, respectively, representing the next times debt holders may exercise this provision.

The Company's obligations to repay certain pollution control revenue bonds are secured by several series of FMB. Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank LOCs of $76 million and noncancelable municipal bond insurance policies of $361 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the LOCs or policies, the Company is entitled to a credit against its obligation to repay that bond. The Company pays annual fees of 0.875% to 1.625% of the amounts of the LOCs to the issuing bank and 0.213% to 0.600% of the amounts of the policies to the insurers and are obligated to reimburse the bank or insurers, as the case maybe, for any drawings thereunder.

Certain secured notes of the Company are entitled to the benefit of noncancelable municipal bond insurance policies of $120 million to pay principal of, or interest on, the applicable notes. To the extent that drawings are made under the policy, the Company is entitled to a credit against its obligation to repay those notes. The Company is obligated to reimburse the insurer for any drawings thereunder.

The Company and TE have unsecured LOCs of approximately $194 million in connection with the sale and leaseback of Beaver Valley Unit 2. The Company and TE are jointly and severally liable for the LOCs (see Note 5).

(D)SUBORDINATED DEBENTURES TO AFFILIATED TRUSTS-

As of December 31, 2005, the Company's wholly owned statutory business trust, Cleveland Electric Financing Trust, had $100 million of outstanding 9.00% preferred securities maturing in 2031. The sole assets of the trust are the Company's subordinated debentures with the same rate and maturity date as the preferred securities.

The Company formed the trust to sell preferred securities and invest the gross proceeds in the 9.00% subordinated debentures of the Company. The sole assets of the trust are the applicable subordinated debentures. Interest payment provisions of the subordinated debentures match the distribution payment provisions of the trust's preferred securities. In addition, upon redemption or payment at maturity of subordinated debentures, the trust's preferred securities will be redeemed on a pro rata basis at their liquidation value. Under certain circumstances, the applicable subordinated debentures could be distributed to the holders of the outstanding preferred securities of the trust in the event that the trust is liquidated. The Company has effectively provided a full and unconditional guarantee of payments due on the trust's preferred securities. The trust's preferred securities are redeemable at 100% of their principal amount at the Company's option beginning in December 2006. Interest on the subordinated debentures (and therefore distributions on the trust's preferred securities) may be deferred for up to 60 months, but the Company may not pay dividends on, or redeem or acquire, any of its cumulative preferred or common stock until deferred payments on its subordinated debentures are paid in full.

11.ASSET RETIREMENT OBLIGATION:

In January 2003, the Company implemented SFAS 143, which provides accounting guidance for retirement obligations associated with tangible long-lived assets. This standard requires recognition of the fair value of a liability for an ARO in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the ARO increases, resulting in a period expense. Upon retirement, a gain or loss would be recognized if the cost to settle the retirement obligation differs from the carrying amount.

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The Company initially identified applicable legal obligations as defined under the standard for nuclear power plant decommissioning of Beaver Valley Unit 2, Davis-Besse and Perry nuclear generating facilities, reclamation of a sludge disposal pond related to the Bruce Mansfield Plant and closure of two coal ash disposal sites. The ARO liability as of the date of adoption was $238 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. The Company’s share of the obligation to decommission these units was developed based on site specific studies performed by an independent engineer. The Company utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.

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 Company. 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 the two coal ash disposal sites and the sale and leaseback arrangements remain with the Company.

The Company implemented FIN 47, "Accounting for Conditional Asset Retirement Obligations", an interpretation of SFAS 143 on December 31, 2005. FIN 47 provides accounting standards for conditional retirement obligations associated with tangible long-lived assets, requiring recognition of the fair value of a liability for an ARO in the period in which it is incurred if a reasonable estimate can be identified. FIN 47 states that anobligation exists even though there may be uncertainty about timing or method of settlement andfurther clarifies SFAS 143, stating that the uncertainty surrounding the timing and method of settlement when settlement is conditional on a future event occurring should be reflected in the measurement of the liability not in the recognition of the liability. The recognition requirement of the conditional ARO under FIN 47 is the same as SFAS 143, in that the associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize a regulatory asset or liability instead if the criteria for such treatment are met. Upon retirement, a gain or loss would be recognized if the cost to settle the retirement obligation differs from the carrying amount.

The Company identified applicable legal obligations as defined under the new standard 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 $7 million (including accumulated accretion for the period from the date the liability was incurred to the date of adoption), an asset retirement cost of $2 million (recorded as part of the carrying amount of the related long-lived asset), and accumulated depreciation of $2 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 $6 million cumulative effect adjustment ($4 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 effect on income as if FIN 47 had been applied during 2004 and 2003 is 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	$	272	$	255
Transfers to FGCO and NCG		(247)		-
Accretion		17		17
Revisions in estimated cash flows		(41)		-
FIN 47 ARO		7		-
Balance at end of year	$	8	$	272

12.SHORT-TERM BORROWINGS:

Short-term borrowings outstanding as of December 31, 2005, consisted of $212 million of borrowings from affiliates and $140 million of CFC borrowings. CFC is a wholly owned subsidiary of the Company whose borrowings are secured by customer accounts receivable purchased from the Company and TE. CFC can borrow up to $200 million under a receivables financing arrangement at rates based on certain bank commercial paper and is required to pay an annual fee of 0.25% on the amount of the entire finance limit. The receivables financing agreement expires in December 2006. As a separate legal entity with separate creditors, CFC would have to satisfy its obligations to creditors before any of its remaining assets could be made available to the Company.

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In June 2005, the Company, FirstEnergy, OE, Penn, 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. The Company's borrowing limit under the facility is $250 million. The average interest rate on short-term borrowings outstanding as of December 31, 2005 and 2004 was 4.2% and 2.1%, respectively.

13.COMMITMENTS AND CONTINGENCIES:

(A) 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.

Regulation of Hazardous Waste

The Company has been named as a PRP at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of December 31, 2005, based on estimates of the total costs of cleanup, the Company’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $1.7 million have been accrued through December 31, 2005.

(B) OTHER LEGAL PROCEEDINGS-

Power Outages and Related Litigation

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of December 31, 2005 for any expenditures in excess of those actually incurred through that date. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators before determining the next steps, if any, in the proceeding.

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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.

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

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. 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 Company, OE, TE and Penn 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. The transfer included the Company's prior interests in Beaver Valley Unit 2 (24.47%), Davis-Besse (51.38%) and Perry (44.85%).

On May 11, 2005, FENOC received a subpoena for documents related to outside meetings attended by Davis-Besse personnel on corrosion and cracking of control rod drive mechanisms and additional root cause evaluations. On January 20, 2006, FENOC announced that it has entered into a deferred prosecution agreement with the U.S. Attorney’s Office for the Northern District of Ohio and the Environmental Crimes Section of the Environment and Natural Resources Division of the DOJ related to FENOC’s communications with the NRC during the fall of 2001 in connection with the reactor head issue at the Davis-Besse Nuclear Power Station. Under the agreement, which expires on December 31, 2006, the United States acknowledged FENOC’s extensive corrective actions at Davis-Besse, FENOC’s cooperation during investigations by the DOJ and the NRC, FENOC’s pledge of continued cooperation in any related criminal and administrative investigations and proceedings, FENOC’s acknowledgement of responsibility for the behavior of its employees, and its agreement to pay a monetary penalty. The DOJ will refrain from seeking an indictment or otherwise initiating criminal prosecution of FENOC for all conduct related to the statement of facts attached to the deferred prosecution agreement, as long as FENOC remains in compliance with the agreement, which FENOC fully intends to do. FENOC has agreed to pay a penalty of $28 million (which is not deductible for income tax purposes) which reduced FirstEnergy's earnings by $0.09 per common share in the fourth quarter of 2005. As part of the deferred prosecution agreement entered into with the DOJ, $4.35 million of that amount will be directed to community service projects.

On April 21, 2005, the NRC issued a NOV and proposed a $5 million civil penalty related to the degradation of the Davis-Besse reactor vessel head issue described above. The Company accrued $1 million for a potential fine prior to 2005 and accrued the remaining liability for the Company's share of the proposed fine of $1.8 million during the first quarter of 2005. On September 14, 2005, FENOC filed its response to the NOV with the NRC. FENOC accepted full responsibility for the past failure to properly implement its boric acid corrosion control and corrective action programs. The NRC NOV indicated that the violations do not represent current licensee performance. FirstEnergy paid the penalty in the third quarter of 2005. On January 23, 2006, FENOC supplemented its response to the NRC's NOV on the Davis-Besse head degradation to reflect the deferred prosecution agreement that FENOC had reached with the DOJ.

Effective July 1, 2005, the NRC oversight panel for Davis-Besse was terminated and Davis-Besse returned to the standard NRC reactor oversight process. At that time, NRC inspections were augmented to include inspections to support the NRC's Confirmatory Order dated March 8, 2004 that was issued at the time of startup and to address an NRC White Finding related to the performance of the emergency sirens. By letter dated December 8, 2005, the NRC advised FENOC that the White Finding had been closed.

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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

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

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 will continue to do so with the formal investigation.

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 any of the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.

14. FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS

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 in FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and FGCO, respectively. The generating plant interests transferred do not include CEI’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 Ohio 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, 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.

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The difference (approximately $33.7 million) between the purchase price specified in the Master Facility Lease and the net book value at the date of transfer was charged to equity. FGCO also assumed certain assets and liabilities relating to the purchased units. As consideration, FGCO delivered to the Company a promissory note of approximately $383.1 million that is secured by a lien on the units purchased, bears interest at a rate per annum based on the weighted cost of CEI’s long-term debt (5.99%) and matures twenty years after the date of issuance. FGCO may pre-pay a portion of the promissory note through refunding from time to time of CEI’s outstanding pollution control debt. The timing of any refunding will be subject to market conditions and other factors.

On December 16, 2005, CEI completed the intra-system transfer of its respective ownership in the nuclear generation assets to NGC through a sale at net book value. 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 $31.6 million) between the purchase price of the generation assets and the net book value at the date of transfer was credited to equity. NGC also assumed CEI’s interest in associated decommissioning trust funds, other related assets and other liabilities associated with the transferred assets. In addition, CEI received a promissory note from NGC in the principal amount of approximately $1.0 billion, representing the net book value of the contributed assets as of September 30, 2005, less other liabilities assumed. The note bears interest at a rate per annum based on CEI’s weighted average cost of long-term debt (5.99%), matures twenty years from the date of issuance, and is subject to prepayment at any time, in whole or in part, by NGC.

These transactions were pursuant to the Ohio Companies’ restructuring plans that were approved by the PUCO under applicable Ohio electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies 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 Company's near-term future results with reductions in revenues and expenses. Revenues will be reduced due to the termination of the sale of its nuclear-generated KWH and  the lease of its non-nuclear generation assets arrangements with FES. The Company's 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. The Company will retain a fossil generation KWH sales arrangement and the portion of expenses related to its retained leasehold interests in the Bruce Mansfield Plant. In addition, the Company will receive interest income from associated company notes receivable from FGCO and NGC for the transfer of its generation net assets. FES will continue to provide the Company's PLR requirements 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	$	1,275
Other property and investments		446
Current assets		72
Deferred charges		-
	$	1,793
Liabilities Related to Assets Transferred
Long-term debt	$	-
Current liabilities		-
Noncurrent liabilities		320
	$	320
Net Assets Transferred	$	1,473

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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 Company is currently evaluating this FSP 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 Company will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006.

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

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

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

In December 2004, the FASB issued SFAS 153 amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective January 1, 2006 for the Company. This FSP is not expected to have a material impact on the Company’s financial statements.

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

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

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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	$	433.2	$	448.7	$	526.4	$	459.8
Operating Expenses and Taxes		387.1		390.5		409.4		372.2
Operating Income		46.1		58.2		117.0		87.6
Other Income		4.3		9.3		24.1		14.2
Net Interest Charges		34.9		28.8		30.7		35.3
Income Before Cumulative Effect of Accounting Change		15.5		38.7		110.4		66.5
Cumulative Effect of Accounting Change (Net of Income Tax Benefit)		-		-		-		(3.7	)
Net Income	$	15.5	$	38.7	$	110.4	$	62.8
Earnings on Common Stock	$	12.6	$	38.7	$	110.4	$	62.8

	March 31,		June 30,		September 30,		December 31,
Three Months Ended	2004		2004		2004		2004
	(In millions)
Operating Revenues	$	426.5	$	440.9	$	504.9	$	436.2
Operating Expenses and Taxes		353.2		363.5		402.5		361.4
Operating Income		73.3		77.4		102.4		74.8
Other Income		11.7		9.5		8.3		12.7
Net Interest Charges		36.6		37.1		28.3		31.6
Net Income	$	48.4	$	49.8	$	82.4	$	55.9
Earnings on Common Stock	$	46.7	$	48.0	$	80.7	$	54.1

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