THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

2006 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 1,600 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	3-19
Consolidated Statements of Income	20
Consolidated Balance Sheets	21
Consolidated Statements of Capitalization	22
Consolidated Statements of Common Stockholder's Equity	23
Consolidated Statements of Preferred Stock	23
Consolidated Statements of Cash Flows	24
Consolidated Statements of Taxes	25
Notes to Consolidated Financial Statements	26-46

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
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
ARO	Asset Retirement Obligation
CAT	Commercial Activity Tax
CBP	Competitive Bid Process
ECAR	East Central Area Reliability Coordination Agreement
EPACT	Energy Policy Act of 2005
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
FIN 46R	FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities"
FIN 47	FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB    Statement No. 143"
FIN 48	FIN 48, "Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109"
FMB	First Mortgage Bonds
Fitch	Fitch Ratings, Ltd.
GAAP	Accounting Principles Generally Accepted in the United States
KWH	Kilowatt-hours
LOC	Letter of Credit
MISO	Midwest Independent Transmission System Operator, Inc.
Moody's	Moody's Investors Service
MSG	Market Support Generation
MW	Megawatts
NERC	North American Electric Reliability Corporation
NOPR	Notice of Proposed Rulemaking
OCC	Ohio Consumers' Council
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
PJM	PJM Interconnection LLC
PLR	Provider of Last Resort
PPUC	Pennsylvania Public Utility Commission
PRP	Potentially Responsible Party
PSA	Power Supply Agreements
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act of 1935
RCP	Rate Certainty Plan
RSP	Rate Stabilization Plan
RTC	Regulatory Transition Charge
S&P	Standard & Poor's Ratings Service

i

GLOSSARY OF TERMS, Cont'd.

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 107	SFAS No. 107, "Disclosures about Fair Value of Financial Instruments"
SFAS 115	SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities"
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 157	SFAS No. 157, "Fair Value Measurements"
SFAS 158	SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement    Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R)"
SFAS 159	SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities - Including an    amendment of FASB Statement No. 115"
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 and cash flows present fairly, in all material respects, the financial position of The Cleveland Electric Illuminating Company and its subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 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.

Our audit was conducted for the purpose of forming an opinion on the basic financial statements taken as a whole. The Supplemental Consolidated Statements of Taxes is presented for purposes of additional analysis and is not a required part of the basic financial statements. Such information has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, is fairly stated in all material respects in relation to the basic financial statements taken as a whole.

As discussed in Note 3 to the consolidated financial statements, the Company changed the manner in which it accounts for defined benefit pension and other postretirement benefit plans as of December 31, 2006. As discussed in Note 2(G) and Note 10 to the consolidated financial statements, the Company changed its method of accounting for conditional asset retirement obligations as of December 31, 2005.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 27, 2007

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
For the Years Ended December 31,	2006			2005			2004			2003			2002
	(Dollars in thousands)
GENERAL FINANCIAL INFORMATION:
Revenues	$	1,769,708		$	1,868,161		$	1,808,485		$	1,719,739		$	1,843,671
Operating Income	$	526,561		$	435,898		$	439,905		$	255,615		$	306,152
Income Before Cumulative Effect of a
Change in Accounting Principle	$	306,051		$	231,058		$	236,531		$	197,033		$	136,952
Net Income	$	306,051		$	227,334		$	236,531		$	239,411		$	136,952
Earnings on Common Stock	$	306,051		$	224,416		$	229,523		$	231,885		$	121,262
Total Assets	$	5,563,498		$	6,101,670		$	6,675,377		$	6,758,501		$	6,500,238
CAPITALIZATION AS OF DECEMBER 31:
Common Stockholder's Equity	$	1,468,903		$	1,942,074		$	1,853,561		$	1,778,827		$	1,200,001
Preferred Stock-
Not Subject to Mandatory Redemption		-			-			96,404			96,404			96,404
Subject to Mandatory Redemption		-			-			-			-			105,021
Long-Term Debt and Other Long-Term Obligations		1,805,871			1,939,300			1,970,117			1,884,643			1,975,001
Total Capitalization	$	3,274,774		$	3,881,374		$	3,920,082		$	3,759,874		$	3,376,427
CAPITALIZATION RATIOS:
Common Stockholder's Equity		44.9	%		50.0	%		47.3	%		47.3	%		35.5	%
Preferred Stock-
Not Subject to Mandatory Redemption		-			-			2.4			2.6			2.9
Subject to Mandatory Redemption		-			-			-			-			3.1
Long-Term Debt and Other Long-Term Obligations		55.1			50.0			50.3			50.1			58.5
Total Capitalization		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%
DISTRIBUTION KWH DELIVERIES (Millions):
Residential		5,441			5,699			5,264			5,216			5,370
Commercial		4,784			4,998			4,817			4,690			4,628
Industrial		8,898			9,041			9,006			8,908			8,921
Other		170			172			162			169			167
Total		19,293			19,910			19,249			18,983			19,086
CUSTOMERS SERVED:
Residential		674,392			675,071			674,292			669,337			677,095
Commercial		85,015			85,033			81,093			80,596			71,893
Industrial		2,270			2,304			2,211			2,318			4,725
Other		295			295			293			286			289
Total		761,972			762,703			757,889			752,537			754,002
NUMBER OF EMPLOYEES		943			949			905			949			974

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 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), and the legal and regulatory changes resulting from the implementation of the Energy Policy Act of 2005 (including, but not limited to, the repeal of the Public Utility Holding Company Act of 1935), the uncertainty of the timing and amounts of the capital expenditures, 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 Nuclear Regulatory Commission and the Public Utilities Commission of Ohio as disclosed in our Securities and Exchange Commission filings, the timing and outcome of various proceedings before the Public Utilities Commission of Ohio (including, but not limited to, the successful resolution of the issues remanded to the Public Utilities Commission of Ohio by the Ohio Supreme Court regarding the Rate Stabilization Plan), the continuing availability and operation of generating units, the inability to accomplish or realize anticipated benefits from strategic goals (including employee workforce initiatives), the anticipated benefits from voluntary pension plan contributions, the ability to improve electric commodity margins and to experience growth in the distribution business, the 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.

Reclassifications

As discussed in Note 1 to the consolidated financial statements, certain prior year amounts have been reclassified to conform to the current year presentation. These reclassifications did not change previously reported earnings for 2005 and 2004. All reclassifications have been evaluated and determined to be properly reflected as reclassifications in the respective period as presented in the Consolidated Balance Sheets and Statements of Cash Flows.

FirstEnergy Intra-System Generation Asset Transfers

In 2005, the Ohio Companies and Penn 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 did not include our leasehold interests in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.

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

On December 16, 2005, we completed the intra-system transfer of our ownership interests in the nuclear generation assets to NGC through 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.

3

The transfers affect our comparative earnings results with reductions in both revenues and expenses. Revenues are reduced due to the termination of certain arrangements with FES, under which we previously sold our nuclear-generated KWH to FES and leased our non-nuclear generation assets to FGCO, a subsidiary of FES. Our expenses are 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. With respect to our retained leasehold interests in the Bruce Mansfield Plant, we have continued the fossil generation KWH sales arrangement with FES and continue to be obligated on the applicable portion of expenses related to those interests. In addition, we receive interest income on associated company notes receivable from the transfer of our generation net assets. FES continues to provide our PLR requirements under revised purchased power arrangements covering the three-year period beginning January 1, 2006 (see Regulatory Matters).

The effects on our results of operations in 2006 compared to 2005 from the generation asset transfers (also reflecting our retained leasehold interests discussed above) are summarized in the following table:

Intra-System Generation Asset Transfers
Income Statement Effects		Increase (Decrease)
	(In millions)
Revenues:
Non-nuclear generating units rent	(a)		$	(49)
Nuclear-generated KWH sales	(b)			(217)
Total - Revenues Effect				(266)
Expenses:
Fuel costs - nuclear	(c)			(34)
Nuclear operating costs	(c)			(174)
Provision for depreciation	(d)			(57)
General taxes	(e)			(15)
Total - Expenses Effect				(280)
Operating Income Effect				14
Other Income (Expense):
Interest income from notes receivable	(f)			57
Nuclear decommissioning trust earnings	(g)			(31)
Interest expense	(h)			12
Capitalized interest	(i)			(1)
Total - Other Income Effect				37
Income Before Income Taxes Effect				51
Income Taxes	(j)			21
Net Income Effect			$	30
(a) Elimination of non-nuclear generation assets lease to FGCO.
(b) Reduction of nuclear-generated wholesale KWH sales to FES.
(c) Reduction of nuclear fuel and operating costs.
(d) Reduction of depreciation expense and asset retirement obligation accretion related to generation assets.
(e) Reduction of property tax expense on generation assets.
(f) Interest income on associated company notes receivable from the transfer of generation net assets.
(g) Reduction of earnings on nuclear decommissioning trusts.
(h) Reduction of interest expense on associated company money pool debt for working capital requirements.
(i) Reduction of allowance for borrowed funds used during construction on nuclear capital expenditures.
(j) Income tax effect of the above adjustments.

Results of Operations

Earnings on common stock in 2006 increased to $306 million from $224 million in 2005. The change in earnings reflected the effects of the generation asset transfer shown in the table above. Excluding the impact of the asset transfer, earnings increased $52 million primarily due to higher revenues and decreased amortization of regulatory assets, partially offset by increased purchased power costs.

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 a change in accounting principle 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.

4

Revenues

Revenues decreased by $98 million or 5.3% in 2006 compared to 2005. Excluding the effects of the generation asset transfers displayed above, revenues increased $168 million primarily due to a $427 million increase in retail generation sales revenues and a $106 million reduction in customer shopping incentives, partially offset by a $246 million decrease in distribution revenues and a $121 million decrease in wholesale sales.

Wholesale revenues from non-affiliates decreased by $72 million in 2006 as a result of the December 2005 cessation of the MSG sales arrangements under our transition plan. We had been required to provide the MSG to non-affiliated alternative suppliers.

Wholesale sales to FES decreased by $49 million in 2006 due primarily to the termination of an arrangement to sell power purchased from TE related to its leasehold interest in Beaver Valley Unit 2. Subsequent to the generation asset transfer, we now retain this purchased power from TE to meet a portion of our retail PLR obligation.

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 were deferred for future recovery under our transition plan and did not affect earnings (see Note 2(A)).

Changes in electric generation KWH sales and revenues in 2006 and 2005, compared to the prior year, are summarized in the following tables.

Changes in Generation KWH Sales	2006			2005
Increase (Decrease)
Electric Generation:
Retail		46.7	%		4.9	%
Wholesale *		(50.6	)%		(2.7	)%
Net Change in Generation Sales		9.3	%		0.5	%

Changes in Generation Revenues	2006			2005
Increase (Decrease)	(In millions)
Retail Generation:
Residential	$	165		$	11
Commercial		150			5
Industrial		112			17
Total Retail Generation		427			33
Wholesale*		(121	)		26
Net Increase in Generation Revenues	$	306		$	59

*Excludes impact of generation asset transfers related to nuclear generated KWH sales.

Increased retail generation revenues in 2006 compared to 2005 (as shown in the table above) were due to higher unit prices and increased KWH sales. The higher unit prices for generation reflected the rate stabilization charge that became effective in the first quarter of 2006 under provisions of the RSP and RCP. The increase in generation KWH sales resulted from decreased customer shopping. Generation services provided by alternative suppliers as a percent of total sales delivered in our service area decreased by: residential - 55.5 percentage points, commercial - 40.5 percentage points and industrial - 8.3 percentage points. The decreased shopping resulted from certain alternative energy suppliers terminating their supply arrangements with our shopping customers in the fourth quarter of 2005.

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 slightly lower KWH sales. 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.

5

Changes in distribution KWH deliveries and revenues in 2006 and 2005, compared to the prior year, are summarized in the following tables.

Changes in Distribution KWH Sales	2006		2005
Increase (Decrease)
Distribution Deliveries:
Residential	(4.5)	%	8.3	%
Commercial	(4.3)	%	3.8	%
Industrial	(1.6)	%	0.4	%
Net Change in Distribution Deliveries	(3.1)	%	3.4	%

Changes in Distribution Revenues	2006		2005
Increase (Decrease)	(In millions)
Residential	$	(59)	$	31
Commercial		(97)		3
Industrial		(90)		(1)
Net Change in Distribution Revenues	$	(246)	$	33

Lower distribution revenues, shown in the table above, for 2006 primarily reflected lower unit prices and decreased KWH deliveries. The lower unit prices reflected the completion of the generation-related transition cost recovery under our transition plan in 2005, partially offset by increased transmission rates to recover MISO costs beginning in 2006 (see Outlook -- Regulatory Matters). The lower KWH distribution deliveries to residential and commercial customers were primarily due to milder weather conditions in 2006 compared to 2005.

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.

Expenses

Total expenses increased by $91 million in 2006 and $64 million in 2005 from the prior year. The change in 2006 was impacted by the effects of the generation asset transfers shown in the table above. Excluding the asset transfer effects, the following table presents changes from the prior year by expense category:

Expenses - Changes	2006			2005
Increase (Decrease)	(In millions)
Fuel costs	$	(2	)	$	8
Purchased power costs		178			14
Nuclear operating costs		-			26
Other operating costs		(10	)		29
Provision for depreciation		(7	)		(4	)
Amortization of regulatory assets		(100	)		31
Deferral of new regulatory assets		35			(46	)
General taxes		(3	)		6
Net increase in expenses	$	91		$	64

Higher purchased power costs in 2006 as compared to 2005 resulted from increased KWH purchases to meet our higher retail generation sales requirements and higher unit prices associated with our current power supply agreement with FES (see Outlook-Regulatory Matters). Lower other operating costs in 2006 compared with 2005 reflected the absence in 2006 of transmission expenses related to the 2005 competitive retail energy supplier reimbursements which were discontinued at the end of 2005. In addition, decreased employee and contractor costs resulted from lower storm-related expenses and higher accelerated reliability improvement projects that were capitalized in 2006 compared to 2005. Partially offsetting the lower other operating costs were increased transmission expenses related to MISO Day 2 operations that began on April 1, 2005.

6

Excluding the effects of the generation asset transfers, the depreciation decrease in 2006 compared to 2005 was primarily attributable to a second quarter 2006 pretax credit adjustment of $6.5 million ($4 million net of tax) applicable to prior periods. Lower amortization of regulatory assets in 2006 reflected the completion of generation-related transition cost amortization under our transition plan, partially offset by the amortization of deferred MISO costs that are being recovered in 2006. The decreased deferral of new regulatory assets in 2006 compared with 2005 was primarily due to the termination of the shopping incentive deferrals ($106 million) and lower MISO cost deferrals ($26 million), partially offset by the deferrals of distribution costs ($57 million) and fuel costs ($39 million) under the RCP. The deferral of interest on the unamortized shopping incentive balances continues under the RCP.

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.

The decrease in depreciation in 2005 compared to 2004 was primarily due to the non-nuclear generation transfer that occurred on October 24, 2005 (see Note 13). Higher amortization of regulatory assets in 2005 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).

Excluding the effects of the generation asset transfers, general taxes decreased $3 million in 2006 primarily due to lower Ohio KWH tax. General taxes increased $6 million in 2005 compared to 2004 primarily due to higher property taxes.

Other Income

The change in other income in 2006 reflects the generation asset transfers discussed above. Excluding the effects of the asset transfer, other income decreased by $17 million in 2006 and was primarily the result of higher interest expense due to the absence of refinancing cost reductions in 2006. Other income increased by $13 million in 2005, primarily due to higher realized gains on nuclear decommissioning trust investments. Net interest charges continued to trend lower, decreasing by $4 million in 2005, due to our debt reduction program. Interest on long-term debt was lower due to redemptions of $2 million and the refinancing of $143 million of pollution control notes during 2005.

Cumulative Effect of a Change in Accounting Principle

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.

Income Taxes

Income taxes increased by $36 million in 2006 compared to 2005. Excluding the effects of the generation asset transfer, income taxes increased by $15 million in 2006. The increase in 2006 was primarily due to an increase in taxable income and by the absence in 2006 of $1 million of reduced income tax expenses from the implementation of Ohio tax legislation changes in the second quarter of 2005. Income taxes increased $15 million in 2005 primarily due to a reserve for potential federal income tax audit adjustments.

7

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 was or will be multiplied by 80% in 2005; 60% in 2006; 40% in 2007 and 20% 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.

Preferred Stock Dividend Requirements

Preferred stock dividend requirements decreased by $3 million in 2006 compared to 2005, as a result of the redemption of our remaining outstanding preferred stock in 2005. Preferred stock dividend requirements decreased by $4 million in 2005 from 2004 principally due to optional preferred stock redemptions of $100 million in 2005.

Capital Resources and Liquidity

During 2007, we expect to meet our contractual obligations with cash from operations, short-term credit arrangements and funds from the capital markets. 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, 2006, we had $221,000 of cash and cash equivalents, compared with $207,000 as of December 31, 2005. The major sources of changes in these balances are summarized below.

Cash Flows from Operating Activities

Our net cash provided from operating activities was $419 million in 2006, $148 million in 2005 and $222 million in 2004, summarized as follows:

Operating Cash Flows	2006			2005			2004
	(In millions)
Net Income	$	306		$	227		$	237
Net non-cash charges (credits)		(43	)		197			206
Pension trust contribution*		7			(63	)		(19	)
Working capital and other		149			(213	)		(202	)
Net cash provided from operating activities	$	419		$	148		$	222

    * Pension trust contributions in 2005 and 2004 are net of $30 million and $13 million of

related current year cash income tax benefits, respectively. The $7 million cash inflow

in 2006 represents reduced income taxes paid in 2006 relating to a January 2007

pension contribution.

Net cash provided from operating activities increased by $271 million in 2006 compared to 2005. The increase of $79 million from net income and the decrease of $240 million in net non-cash charges are described above under "Results of Operations." The tax benefit in 2006 relating to the January 2007 pension contribution and the absence in 2006 of the pension trust contribution in 2005 also contributed to the increase. The largest factors affecting the $362 million increase in working capital and other operating cash flows for 2006 are changes in accounts payable of $376 million primarily for the repurchase of $300 million in common stock from FirstEnergy in December 2006. Partially offsetting the increase is the absence of funds received in 2005 for prepaid electric service under the Energy for Education Program.

8

Net cash provided from operating activities decreased by $74 million in 2005 compared to 2004. The decreases of $10 million from net income and $9 million in net non-cash charges are described above under "Results of Operations." There was a $44 million decrease in after-tax voluntary pension plan contributions and an $11 million decrease from working capital and other cash flows. The change in working capital and other operating cash flows was principally due to a decrease in cash provided from the settlement of receivables of $141 million, 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 the Energy for Education Program.

Cash Flows from Financing Activities

In 2006, 2005 and 2004, net cash used for financing activities was $704 million, $71 million and $98 million, respectively, primarily reflecting the new issues and redemptions shown below.

Securities Issued or Redeemed	2006			2005		2004
	(In millions)
New Issues:
Pollution Control Notes	$	-		$	141	$	125
Unsecured Notes		296			-		-
Redemptions:
Pollution Control Notes	$	376		$	147	$	46
Secured Notes		-			-		288
Common Stock		300			-		-
Preferred Stock		-			102		1
Other		-			1		1
	$	676		$	250	$	336
Short-term borrowings (repayments), net	$	(143	)	$	156	$	290

Net cash used for financing activities increased by $633 million in 2006 compared to 2005. The increase in funds used for financing activities primarily resulted from a $570 million increase in net preferred stock and debt redemptions and the absence of a $75 million equity contribution from FirstEnergy in 2005, partially offset by an $11 million decrease in common stock dividend payments to FirstEnergy.

We had $27 million of cash and temporary investments (which included short-term notes receivable from associated companies) and approximately $218 million of short-term indebtedness as of December 31, 2006. We have obtained authorization from the PUCO to incur short-term debt of up to $600 million (including the bank facility and utility money pool described below).

At the end of 2006, we had the capability to issue $523 million of additional FMB on the basis of property additions and retired bonds under the terms of our mortgage indenture. The 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 under the indenture to incur additional secured debt not otherwise permitted by a specified exception of up to $491 million as of December 31, 2006. We have no restrictions on the issuance of preferred stock.

CFC is our wholly owned subsidiary whose borrowings are secured by customer accounts receivable purchased from us and TE. CFC can borrow up to $200 million under a receivables financing arrangement. 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. As of December 31, 2006, the facility was undrawn.

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 during 2006 was 5.22%.

9

On August 24, 2006, we, FirstEnergy, OE, Penn, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, have entered into a new $2.75 billion five-year revolving credit facility which replaced the prior $2 billion credit facility. Subject to specified conditions, FirstEnergy may request an increase in the total commitments available under the new facility up to a maximum of $3.25 billion.Commitments under the new facility are available until August 24, 2011, unless the lenders agree, at the request of the Borrowers, to two additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each Borrower are subject to a specified sublimit, as well as applicable regulatory and other limitations. 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 was $450 million as of December 31, 2006.

The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of December 31, 2006, our debt to total capitalization as defined under the revolving credit facility was 57%.

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

Our access to the capital markets and the costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy. The ratings outlook from S&P on all such securities is stable. The ratings outlook from Moody's and 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		BBB-

In April, May and December of 2006, pollution control notes totaling $376 million that were formerly our obligations were refinanced and became obligations of FGCO and NGC. The proceeds from the refinancings were used to repay a portion of our associated company notes receivable from FGCO and NGC. Approximately $353 million of remaining pollution control notes are subject to transfer.

On December 11, 2006, we issued $300 million of 5.95% senior unsecured notes due 2036. The proceeds of the offering were used to repurchase approximately $300 million of our common stock from FirstEnergy.

Cash Flows from Investing Activities

Net cash provided from investing activities increased by $362 million in 2006 compared to 2005. The change was primarily due to increased loan repayments from associated companies, the absence of net investments in nuclear decommissioning trust funds due to the nuclear generation asset transfer and lower expenditures for property additions partially offset by decreased collection of principal on long-term notes receivable.

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.

Our capital spending for the period 2007-2011 is expected to be approximately $841 million of which approximately $158 million applies to 2007. The capital spending is primarily for property additions supporting the distribution of electricity. In addition, there is capital spending for our leasehold interests in certain generating plants retained after the generation assets transfers in 2005.

10

Contractual Obligations

As of December 31, 2006, our estimated cash payments under existing contractual obligations that we consider firm obligations are as follows:

					2008-		2010-
Contractual Obligations	Total		2007		2009		2011		Thereafter
	(In millions)
Long-term debt (1)	$	1,919	$	120	$	302	$	38	$	1,459`
Short-term borrowings		218		218		-		-		-
Interest on long-term debt		1,480		114		202		171		993
Capital leases		6		1		2		2		1
Operating leases (2)		183		14		31		21		117
Pension funding(3)		25		25		-		-		-
Purchases (4)		607		55		134		182		236
Total	$	4,438	$	547	$	671	$	414	$	2,806

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

          ⁽²⁾ Operating lease payments are net of capital trust receipts of $441.5 million (see Note 5).

    ⁽³⁾ We estimate that no further pension contributions will be required during the 2008-2011 period to maintain our defined benefit pension plan's funding

               at a minimum required level as determined by government regulations. We are unable to estimate projected contributions beyond 2011. See Note 3

               to the consolidated financial statements.

          ⁽⁴⁾             Fuel and power purchases under contracts with fixed or minimum quantities and approximate timing.

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, 2006, the present value of these operating lease commitments, net of trust investments, total $97 million.

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	2007				2008			2009			2010			2011			after			Total			Value
	(Dollars in millions)
Assets
Investments Other Than Cash
and Cash Equivalents-
Fixed Income	$		36		$	38		$	40		$	52		$	57		$	787		$	1,010		$	1,076
Average interest rate			7.7	%		7.7	%		7.7	%		7.7	%		7.7	%		6.6	%		6.9	%
Liabilities
Long-term Debt and Other
Long-Term Obligations:
Fixed rate		$	120		$	140		$	162		$	18		$	20		$	1,324		$	1,784		$	1,864
Average interest rate			7.1	%		7.0	%		7.5	%		7.7	%		7.7	%		6.7	%		6.8	%
Variable rate																	$	135		$	135		$	136
Average interest rate																		3.7	%		3.7	%
Short-term Borrowings		$	218																	$	218		$	218
Average interest rate			5.7	%																	5.7	%

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.

11

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.

On October 21, 2003, the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to the PUCO's concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming the PUCO's order in all respects, except it remanded back to the PUCO the matter of ensuring the availability of sufficient means for customer participation in the marketplace. The RSP contained a provision that permitted the Ohio Companies to withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies have 30 days from the final order or decision to provide notice of termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding on Remand. In their Request, the Ohio Companies provided notice of termination to those provisions of the RSP subject to termination, subject to being withdrawn, and also set forth a framework for addressing the Supreme Court of Ohio's findings on customer participation. If the PUCO approves a resolution to the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies' termination will be withdrawn and considered to be null and void. On July 26, 2006, the PUCO issued an Entry directing the Ohio Companies to file a plan in a new docket to address the Court's concern. The Ohio Companies filed their RSP Remand CBP on September 29, 2006. Initial comments were filed on January 12, 2007 and reply comments were filed on January 29, 2007. In their reply comments the Ohio Companies described the highlights of a new tariff offering they would be willing to make available to customers that would allow customers to purchase renewable energy certificates associated with a renewable generation source, subject to PUCO approval. No further proceedings are scheduled at this time.

The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP filed on September 9, 2005. Major provisions of the RCP include:

Maintaining the existing level of our base distribution rates through April 30, 2009;

Deferring and capitalizing for future recovery (over a 25-year period) with carrying charges certain distribution costs to be incurred during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three years;

Adjusting 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;

Reducing  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

Deferring and capitalizing (for recovery over a 25-year period) increased fuel costs above the amount collected through the Ohio Companies' fuel recovery mechanism.

The following table provides our estimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2007 through 2010:

Period		Amortization
		(In millions)
2007	$	108
2008		124
2009		216
2010		273
Total Amortization	$	721

12

On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies' RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. On January 10, 2006, the Ohio Companies filed a Motion for Clarification seeking clarity on a number of issues. On January 25, 2006, the PUCO issued an Entry on Rehearing granting in part, and denying in part, the Ohio Companies' previous requests and clarifying issues referred to above. The PUCO granted the Ohio Companies' requests to:

Recognize fuel and distribution deferrals commencing January 1, 2006;

Recognize distribution deferrals on a monthly basis prior to review by the PUCO Staff;

Clarify that the types of distribution expenditures included in the Supplemental Stipulation may be deferred; and

Clarify that distribution expenditures do not have to be "accelerated" in order to be deferred.

The PUCO approved the Ohio Companies' methodology for determining distribution deferral amounts, but denied the Motion in that the PUCO Staff must verify the level of distribution expenditures contained in current rates, as opposed to simply accepting the amounts contained in the Ohio Companies' Motion. On February 3, 2006, several other parties filed applications for rehearing, which the PUCO denied on March 1, 2006. Two of these parties subsequently filed notices of appeal with the Supreme Court of Ohio. The Ohio Supreme Court scheduled this case for oral argument on February 27, 2007. On January 31, 2007, the Ohio Companies filed a stipulation which, among other matters and subject to PUCO approval, affirmed that the supplemental stipulation in the RCP would be implemented. This stipulation was approved by the PUCO on February 14, 2007.

On December 30, 2004, the Ohio Companies 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 Ohio Companies requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. The parties reached a settlement agreement that was approved by the PUCO on August 31, 2005. The incremental transmission and ancillary service revenues recovered from January 1 through June 30, 2006 were approximately $54 million. That amount included the recovery of a portion of the 2005 deferred MISO expenses as described below. On April 27, 2006, the Ohio Companies filed the annual update rider to determine revenues ($124 million) from July 2006 through June 2007. The filed rider went into effect on July 1, 2006.

The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for the Ohio Companies 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 Ohio Companies to accrue carrying charges on the deferred balances. On August 31, 2005, the OCC appealed the PUCO's decision. On January 20, 2006, the OCC sought rehearing of the PUCO's approval of the recovery of deferred costs through the rider during the period January 1, 2006 through June 30, 2006. The PUCO denied the OCC's application on February 6, 2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. On March 27, 2006, the OCC filed a motion to consolidate this appeal with the deferral appeals discussed above and to postpone oral arguments in the deferral appeal until after all briefs are filed in this most recent appeal of the rider recovery mechanism. On March 20, 2006, the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of the Ohio Companies' case with a similar case involving Dayton Power & Light Company. Oral arguments were heard on May 10, 2006. On November 29, 2006, the Ohio Supreme Court issued its opinion upholding the PUCO's determination that the Ohio Companies may defer transmission and ancillary service related costs incurred on and after December 30, 2004. The Ohio Supreme Court also determined that the PUCO erred when it denied the OCC intervention, but further ruled that such error did not prejudice OCC and, therefore, the Ohio Supreme Court did not reverse or remand the PUCO on this ground. The Ohio Supreme Court also determined that the OCC's appeal was not premature. No party filed a motion for reconsideration with the Ohio Supreme Court.

On November 1, 2005, FES filed a power sales agreement for approval with the FERC. The 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 CBP results in a lower price for retail customers.

13

On December 29, 2005, the FERC issued an order setting the power sales agreement for hearing. The order criticized the Ohio CBP, and required FES to submit additional evidence in support of the reasonableness of the prices charged in the power sales agreement. On July 14, 2006, the Chief Judge granted the joint motion of FES and the Trial Staff to appoint a settlement judge in this proceeding and the procedural schedule was suspended pending settlement discussions among the parties. A settlement conference was held on September 5, 2006. FES, the Ohio Companies and the PUCO, along with other parties, reached an agreement to settle the case. The settlement was filed with the FERC on October 17, 2006, and was unopposed by the remaining parties, including the FERC Trial Staff. This settlement was accepted by the FERC on December 8, 2006.

The terms of the settlement provide for modification of the power supply agreement with FES. Under the power supply agreement, separate rates are established for the Ohio Companies' PLR requirements; special retail contract requirements, wholesale contract requirements, and interruptible buy-through retail load requirements. For their PLR and special retail contract requirements, the Ohio Companies will pay FES no more than the lower of (i) the sum of the retail generation charge, the rate stabilization charge, the fuel recovery mechanism charge, and FES' actual incremental fuel costs for such sales; or (ii) the wholesale price cap. Different wholesale price caps are imposed for PLR sales, special retail contracts, and wholesale contracts. The wholesale price for interruptible buy-through retail load requirements is limited to the actual spot price of power obtained by FES to provide this power. FES billed the Ohio Companies for the additional amount payable to FES for incremental fuel costs on power supplied during 2006. The total power supply cost billed by FES was lower in each case than the wholesale price caps specified in the settlement accepted by the FERC.

On February 15, 2007, MISO filed documents with the FERC to establish a market-based, competitive ancillary services market. MISO contends that the filing will integrate operating reserves into MISO's existing day-ahead and real-time settlements process, incorporate opportunity costs into these markets, address scarcity pricing through the implementation of a demand curve methodology, foster demand response in the provision of operating reserves, and provide for various efficiencies and optimization with regard to generation dispatch. The filing also proposes amendments to existing documents to provide for the transfer of balancing functions from existing local balancing authorities to MISO. MISO will then carry out this reliability function as the NERC-certified balancing authority for the MISO region. MISO is targeting implementation for the second or third quarter of 2008. The FERC has established March 23, 2007, as the date for interested parties to submit comments addressing the filing. The filing has not yet been fully evaluated to assess its impact on our operations.

On February 16, 2007, the FERC issued a final rule that revises its decade-old open access transmission regulations and policies. The FERC explained that the final rule is intended to strengthen non-discriminatory access to the transmission grid, facilitate FERC enforcement, and provide for a more open and coordinated transmission planning process. The final rule will not be effective until 60 days after publication in the Federal Register. The final rule has not yet been fully evaluated to assess its impact on our operations.

See Note 8 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 become both probable and reasonably estimable.

         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, 2006, 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 $1.8 million as of December 31, 2006.

See Note 12(A) to the consolidated financial statements for further details and a complete discussion of environmental matters.

14

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 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 Web site (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. 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 is also 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 that could require additional material expenditures.

FirstEnergy companies also are defending five separate complaint cases before the PUCO relating to the August 14, 2003 power outages. 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. Three other pending PUCO complaint cases were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of these three cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc., as well) for claims paid to insureds for damages 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. A sixth case involving the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003 was dismissed. On March 7, 2006, the PUCO issued a ruling, consolidating all of the pending outage cases for hearing; limiting the litigation to service-related claims by customers of the Ohio operating companies; dismissing FirstEnergy as a defendant; and ruling that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence. In response to a motion for rehearing filed by one of the claimants, the PUCO ruled on April 26, 2006 that the insurance company claimants, as insurers, may prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities that provide their service. The PUCO denied all other motions for rehearing. The plaintiffs in each case have since filed amended complaints and the named FirstEnergy companies have answered and also have filed a motion to dismiss each action. On September 27, 2006, the PUCO dismissed certain parties and claims and otherwise ordered the complaints to go forward to hearing. The cases have been set for hearing on October 16, 2007.

On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga County Common Pleas Court seeking reimbursement for claims paid to numerous insureds who allegedly suffered losses as a result of the August 14, 2003 outages. All of the insureds appear to be non-customers. The plaintiff insurance companies are the same claimants in one of the pending PUCO cases. FirstEnergy, the Ohio Companies and Penn were served on October 27, 2006. On January 18, 2007, the Court granted the Companies' motion to dismiss the case. It is unknown whether or not the matter will be further appealed. No estimate of potential liability is available 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.

15

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, we were 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 now repealed PUHCA. Concurrent with this notification, we received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, we 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-related disclosures, which has been provided. We have cooperated fully with the informal inquiry and continue to do so with the formal investigation.

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 12(B) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

Critical Accounting Policies

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

Regulatory Accounting

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

Revenue Recognition

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

Pension and Other Postretirement Benefits Accounting

Our reported costs of providing non-contributory qualified and non-qualified 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.

16

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.

As of December 31, 2006, we adopted SFAS 158 which requires a net liability or asset to be recognized for the overfunded or underfunded status of our defined benefit pension and other postretirement benefit plans on the balance sheet and recognize changes in funded status in the year in which the changes occur through other comprehensive income. We will continue to apply the provisions of SFAS 87 and SFAS 106 in measuring plan assets and benefit obligations as of the balance sheet date and in determining the amount of net periodic benefit cost. FirstEnergy's underfunded status at December 31, 2006 is $637 million.

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. The assumed discount rate as of December 31, 2006 is 6.00% from 5.75% and 6.00% used as of December 31, 2005 and 2004, respectively.

FirstEnergy's 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 2006, 2005 and 2004, the FirstEnergy plan assets actually earned $567 million or 12.5%, $325 million or 8.2% and $415 million or 11.1%, respectively. FirstEnergy's pension costs in 2006, 2005 and 2004 were computed using an assumed 9.0% rate of return on plan assets which generated $396 million, $345 million and $286 million expected returns on plan assets, respectively. The 2006 expected return was based upon projections of future returns and FirstEnergy's pension trust investment allocation of approximately 64% equities, 29% bonds, 5% real estate, 1% private equities and 1% cash. The gains or losses generated as a result of the difference between expected and actual returns on plan assets are deferred and amortized and will increase or decrease future net periodic pension expense, respectively.

FirstEnergy's pension and OPEB expense was $94 million in 2006 and $131 million in 2005. On January 2, 2007 FirstEnergy made a $300 million voluntary contribution to its pension plan (our share was $25 million). In addition during 2006, FirstEnergy amended its OPEB plan effective in 2008 to cap its monthly contribution for many of the retirees and their spouses receiving subsidized health care coverage. As a result of the $300 million voluntary contribution and the amendment to the OPEB plan effective in 2008, we expect the pension and OPEB costs for 2007 to be a credit of $94 million for FirstEnergy.

Increase in Costs from Adverse Changes in Key Assumptions
Assumption	Adverse Change		Pension		OPEB		Total
			(In millions)
Discount rate		Decrease by 0.25%	$	0.8	$	0.2	$	1
Long-term return on assets		Decrease by 0.25%	$	1	$	-	$	1
Health care trend rate		Increase by 1%		na	$	0.5	$	0.5

Health care cost trends have significantly increased and will affect future OPEB costs. The 2006 and 2005 composite health care trend rate assumptions are approximately 9-11%, gradually decreasing to 5% in later years. In determining our trend rate assumptions, we included the specific provisions of our health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. The effect on our portion of pension and OPEB costs from changes in key assumptions are as follows:

         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 had 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)).

17

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 2006, 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, 2006, 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

SFAS 159 - The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115

In February 2007, FASB issued SFAS 159, which provides companies with an option to report selected financial assets and liabilities at fair value. The Standard requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company's choice to use fair value on its earnings. The Standard also requires companies to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. This guidance does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS 157, Fair Value Measurements, and SFAS 107, Disclosures about Fair Value of Financial Instruments. We are currently evaluating the impact of this Statement on our financial statements.

SFAS 157 - "Fair Value Measurements"

In September 2006, the FASB issued SFAS 157, that establishes how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. This Statement addresses the need for increased consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. The key changes to current practice are: (1) the definition of fair value which focuses on an exit price rather than entry price; (2) the methods used to measure fair value such as emphasis that fair value is a market-based measurement, not an entity-specific measurement, as well as the inclusion of an adjustment for risk, restrictions and credit standing; and (3) the expanded disclosures about fair value measurements. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. We are currently evaluating the impact of this Statement on its financial statements.

18

FIN 48 - "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109"

In June 2006, the FASB issued FIN 48 which clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with FASB Statement No. 109, "Accounting for Income Taxes." This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken on a tax return. This interpretation also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and transition. The evaluation of a tax position in accordance with this interpretation will be a two-step process. The first step will determine if it is more likely than not that a tax position will be sustained upon examination and should therefore be recognized. The second step will measure a tax position that meets the more likely than not recognition threshold to determine the amount of benefit to recognize in the financial statements. This interpretation is effective for fiscal years beginning after December 15, 2006. We do not expect this Statement to have a material impact on our financial statements.

19

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2006			2005			2004
	(In thousands)
REVENUES (Note 2(I))
Electric sales	$	1,702,089			1,799,211			1,741,511
Excise tax collections		67,619			68,950			66,974
		1,769,708			1,868,161			1,808,485
EXPENSES (Note 2(I)):
Fuel		50,291			85,993			78,072
Purchased power		704,517			557,593			543,949
Nuclear operating costs		-			142,698			117,091
Other operating costs		290,904			301,366			272,303
Provision for depreciation		63,589			127,959			131,854
Amortization of regulatory assets		127,403			227,221			196,501
Deferral of new regulatory assets		(128,220	)		(163,245	)		(117,466	)
General taxes		134,663			152,678			146,276
Total expenses		1,243,147			1,432,263			1,368,580
OPERATING INCOME		526,561			435,898			439,905
OTHER INCOME (EXPENSE) (Notes 2(I) and 7):
Investment income		100,816			86,898			77,090
Miscellaneous income (expense)		6,428			(9,031	)		(8,041	)
Interest expense		(141,710	)		(132,226	)		(138,678	)
Capitalized interest		2,618			2,533			5,110
Total other expense		(31,848	)		(51,826	)		(64,519	)
INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		494,713			384,072			375,386
INCOME TAXES		188,662			153,014			138,855
INCOME BEFORE CUMULATIVE EFFECT OF
A CHANGE IN ACCOUNTING PRINCIPLE		306,051			231,058			236,531
Cumulative effect of a change in accounting principle (net of income
tax benefit of $2,101,000) (Note 2(G))		-			(3,724	)		-
NET INCOME		306,051			227,334			236,531
PREFERRED STOCK DIVIDEND REQUIREMENTS		-			2,918			7,008
EARNINGS ON COMMON STOCK	$	306,051		$	224,416		$	229,523
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

20

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31,	2006			2005
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	221		$	207
Receivables-
Customers (less accumulated provisions of $6,783,000 and			245,193			268,427
$5,180,000, respectively, for uncollectible accounts)
Associated companies			249,735			86,564
Other			14,240			16,466
Notes receivable from associated companies			27,191			19,378
Prepayments and other			2,314			1,903
			538,894			392,945
UTILITY PLANT:
In service			2,136,766			2,030,935
Less - Accumulated provision for depreciation			819,633			788,967
			1,317,133			1,241,968
Construction work in progress			46,385			51,129
			1,363,518			1,293,097
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies			486,634			1,057,337
Investment in lessor notes (Note 6)			519,611			564,166
Other			13,426			12,840
			1,019,671			1,634,343
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill			1,688,521			1,688,966
Regulatory assets			854,588			862,193
Prepaid pension costs (Note 3)			-			139,012
Property taxes			65,000			63,500
Other			33,306			27,614
			2,641,415			2,781,285
		$	5,563,498		$	6,101,670
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt		$	120,569		$	75,718
Short-term borrowings-
Associated companies			218,134			212,256
Other			-			140,000
Accounts payable-
Associated companies			365,678			74,993
Other			7,194			4,664
Accrued taxes			128,829			121,487
Accrued interest			19,033			18,886
Lease market valuation liability			60,200			60,200
Other			52,101			61,308
			971,738			769,512
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity			1,468,903			1,942,074
Long-term debt and other long-term obligations			1,805,871			1,939,300
			3,274,774			3,881,374
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			470,707			554,828
Accumulated deferred investment tax credits			20,277			23,908
Lease market valuation liability			547,800			608,000
Retirement benefits			123,072			83,414
Deferred revenues - electric service programs			51,588			71,261
Other			103,542			109,373
			1,316,986			1,450,784
COMMITMENTS AND CONTINGENCIES (Notes 5 and 12)
		$	5,563,498		$	6,101,670
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.

21

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31,		2006			2005
	(Dollars in thousands)
COMMON STOCKHOLDER'S EQUITY:
Common stock, without par value, 105,000,000 shares authorized		$	860,133		$	1,354,924
67,930,743 and 79,590,689 shares outstanding, respectively
Accumulated other comprehensive loss (Note 2(F))			(104,431	)		-
Retained earnings (Note 9(A))			713,201			587,150
Total			1,468,903			1,942,074
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 9(C)):
First mortgage bonds-
6.860% due 2008			125,000			125,000
Total			125,000			125,000
Secured notes-
7.130% due 2007			120,000			120,000
7.430% due 2009			150,000			150,000
*  3.150% due 2015			-			39,835
7.880% due 2017			300,000			300,000
*  3.150% due 2018			-			72,795
*  3.580% due 2020			-			47,500
6.000% due 2020			62,560			62,560
6.100% due 2020			70,500			70,500
5.375% due 2028			5,993			5,993
*  3.350% due 2030			-			23,255
*  3.750% due 2030			81,640			81,640
*  3.150% due 2033			-			30,000
*  3.150% due 2033			-			46,100
*  3.050% due 2034			-			40,900
*  3.500% due 2034			-			2,900
*  3.650% due 2035			53,900			53,900
*3.500% due 2035			-			45,150
Total			844,593			1,193,028
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
5.950% due 2036			300,000			-
7.742% due to associated companies 2008-2016 (Note 6)			167,696			176,847
Total			949,489			686,340
Capital lease obligations (Note 5)			4,371			4,939
Net unamortized premium on debt			2,987			5,711
Long-term debt due within one year			(120,569	)		(75,718	)
Total long-term debt and other long-term obligations			1,805,871			1,939,300
TOTAL CAPITALIZATION		$	3,274,774		$	3,881,374
* Denotes variable rate issue with applicable year-end interest rate shown.
The accompanying Notes to Conslidated Financial Statements are an integral part of these statements.

22

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, 2004					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 tax benefits		(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
Net income	$	306,051												306,051
Net liability for unfunded retirement benefits
due to the implementation of SFAS 158, net
of $69,609,000 of income tax benefits											(104,431	)
Repurchase of common stock					(11,659,946	)		(300,000	)
Affiliated company asset transfers (see Note 13)								(194,910	)
Restricted stock units								86
Stock based compensation								33
Cash dividends on common stock														(180,000	)
Balance, December 31, 2006					67,930,743		$	860,133		$	(104,431	)	$	713,201

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, 2004		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		-			-			-			-
Balance, December 31, 2006		-		$	-			-		$	-
* 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.

23

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,	2006			2005			2004
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	306,051		$	227,334		$	236,531
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		63,589			127,959			131,854
Amortization of regulatory assets		127,403			227,221			196,501
Deferral of new regulatory assets		(128,220	)		(163,245	)		(117,466	)
Nuclear fuel and capital lease amortization		239			25,803			28,239
Deferred rents and lease market valuation liability		(71,943	)		(67,353	)		(56,405	)
Deferred income taxes and investment tax credits, net		(17,093	)		42,024			39,129
Accrued compensation and retirement benefits		2,367			4,624			15,678
Cumulative effect of a change in accounting principle		-			3,724			-
Pension trust contribution		-			(93,269	)		(31,718	)
Tax refund related to pre-merger period		-			9,636			-
Decrease (increase) in operating assets-
Receivables		(137,711	)		(103,018	)		38,297
Materials and supplies		-			(12,934	)		(8,306	)
Prepayments and other current assets		160			233			2,375
Increase (decrease) in operating liabilities-
Accounts payable		293,214			(82,434	)		(93,745	)
Accrued taxes		7,342			(7,967	)		(73,068	)
Accrued interest		147			(3,216	)		(15,770	)
Electric service prepayment programs		(19,673	)		53,447			(18,386	)
Other		(6,626	)		(40,878	)		(51,617	)
Net cash provided from operating activities		419,246			147,691			222,123
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		295,662			141,004			124,977
Short-term borrowings, net		-			155,883			290,263
Equity contribution from parent		-			75,000			-
Redemptions and Repayments-
Common stock		(300,000	)		-			-
Preferred stock		-			(101,900	)		(1,000	)
Long-term debt		(376,702	)		(147,923	)		(335,393	)
Short-term borrowings, net		(143,272	)		-			-
Dividend Payments-
Common stock		(180,000	)		(191,000	)		(170,000	)
Preferred stock		-			(2,260	)		(7,008	)
Net cash used for financing activities		(704,312	)		(71,196	)		(98,161	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(119,795	)		(148,783	)		(121,316	)
Loan repayments from (loans to) associated companies, net		(7,813	)		(387,746	)		9,936
Collection of principal on long-term notes receivable		376,135			466,378			482
Investments in lessor notes		44,556			32,479			9,270
Proceeds from nuclear decommissioning trust fund sales		-			490,958			406,375
Investments in nuclear decommissioning trust funds		-			(519,982	)		(435,399	)
Other		(8,003	)		(9,789	)		(17,895	)
Net cash provided from (used for) investing activities		285,080			(76,485	)		(148,547	)
Net increase (decrease) in cash and cash equivalents		14			10			(24,585	)
Cash and cash equivalents at beginning of year		207			197			24,782
Cash and cash equivalents at end of year	$	221		$	207		$	197
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	135,276		$	144,730		$	152,373
Income taxes	$	180,941		$	116,323		$	144,277
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

24

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF TAXES
For the Years Ended December 31,	2006			2005			2004
	(In thousands)
GENERAL TAXES:
Real and personal property	$	61,289		$	77,822		$	74,206
Ohio kilowatt-hour excise*		67,619			68,950			66,974
Social security and unemployment		5,179			5,282			4,496
Other		576			624			600
Total general taxes	$	134,663		$	152,678		$	146,276
PROVISION FOR INCOME TAXES:
Currently payable-
Federal	$	173,520		$	90,152		$	72,264
State		32,235			22,939			27,463
		205,755			113,091			99,727
Deferred, net-
Federal		(14,624	)		28,310			34,450
State		1,162			16,350			9,774
		(13,462	)		44,660			44,224
Investment tax credit amortization		(3,631	)		(4,737	)		(5,096	)
Total provision for income taxes	$	188,662		$	153,014		$	138,855
RECONCILIATION OF FEDERAL INCOME TAX
EXPENSE AT STATUTORY RATE TO TOTAL
PROVISION FOR INCOME TAXES:
Book income before provision for income taxes	$	494,713		$	384,072		$	375,386
Federal income tax expense at statutory rate	$	173,150		$	134,425		$	131,385
Increases (reductions) in taxes resulting from-
State income taxes, net of federal income tax benefit		21,708			25,537			24,205
Amortization of investment tax credits		(3,631	)		(4,737	)		(5,096	)
Other, net		(2,565	)		(2,211	)		(11,639	)
Total provision for income taxes	$	188,662		$	153,014		$	138,855
ACCUMULATED DEFERRED INCOME TAXES AS OF
DECEMBER 31:
Property basis differences	$	533,682		$	498,079		$	502,625
Regulatory transition charge		116,229			159,535			221,386
Asset retirement obligations		2,045			-			24,638
Unamortized investment tax credits		(8,839	)		(10,150	)		(23,208	)
Deferred gain on asset sales to affiliated companies		30,730			33,329			33,841
Other comprehensive income		(69,609	)		-			12,548
Above market leases		(234,572	)		(256,297	)		(300,000	)
Retirement benefits		11,048			12,005			(21,674	)
Deferred customer shopping incentive		132,343			153,750			121,778
Other		(42,350	)		(35,423	)		(31,723	)
Net deferred income tax liability	$	470,707		$	554,828		$	540,211
*  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.

25

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 13 - 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.

Certain prior year amounts have been reclassified to conform to the current year presentation. These reclassifications did not change previously reported earnings for 2005 and 2004.

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.

26

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

	2006			2005
	(In millions)
Regulatory transition costs	$360			$479
Customer shopping incentives		368			427
Employee postretirement benefit costs		10			12
Asset removal costs		(12	)		(90	)
MISO transmission costs		26			30
Fuel costs'RCP		39			-
Distribution costs'RCP		57			-
Other		7			4
Total	$	855		$	862

The Company had 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 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 allows 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. In addition, the RCP allows the Company to defer certain increased fuel costs above the amount collected through a PUCO approved fuel recovery mechanism. See Note 8 for further discussion of the recovery of the shopping incentives and the new cost deferrals.

Transition Cost Amortization-

The Company amortizes transition costs (see Note 8) using the effective interest method. Extended RTC amortization will be equal to the related revenue recovery that is recognized beginning in 2009. The following table provides the estimated net amortization of regulatory transition costs and Extended RTC amounts (including associated carrying charges) under the RCP for the period 2007 through 2010:

Period	Amortization
	(In millions)
2007	$	108
2008		124
2009		216
2010		273
Total Amortization	$	721

(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 historical customer usage, load profiles, weather impacts, customer shopping activity, 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.

27

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, 2006, with respect to any particular segment of the Company's customers. Total customer receivables were $245 million (billed - $137 million and unbilled - $108 million) and $268 million (billed - $157 million and unbilled - $111 million) as of December 31, 2006 and 2005, respectively.

The Company and TE sell substantially all of their retail customer receivables to CFC, a wholly owned subsidiary of the Company. In June 2005, the CFC receivables financing structure was restructured from an off-balance sheet transaction to an on-balance sheet transaction. Under the new structure, any borrowings under the facility appear on the Company's consolidated balance sheet as short-term debt. The receivables financing agreement expires on December 5, 2007.

(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.

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 3.2% in 2006, 2.9% in 2005, and 2.8% in 2004.

Asset Retirement Obligations

The Company recognizes a liability for retirement obligations associated with tangible assets in accordance with SFAS 143 and FIN 47. These standards require recognition of the fair value of a liability for an ARO in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and depreciated over time, as described further in Note 10, "Asset Retirement Obligations."

(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 2006 annual review was completed in the third quarter of 2006 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, 2006, 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.

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(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 excluding the effect from the adoption of SFAS 158 at December 31, 2006, except those resulting from transactions with FirstEnergy and preferred stockholders. As of December 31, 2006, accumulated other comprehensive loss consisted of a net liability for unfunded retirement benefits due to the implementation of SFAS 158, net of tax benefits (see Note 3) of $104 million. As of December 31, 2005, the Company did not have an accumulated other comprehensive balance.

(G) CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE-

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).

(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 assets and liabilities related to tax and accounting basis differences and tax credit carryforwards are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. 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 7 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. 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 13). 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. The primary affiliated company's transactions are as follows:

	2006		2005		2004
	(In millions)
Revenues:
PSA revenues from FES	$	95	$	362	$	387
Generating units rent from FES		-		49		59
Ground lease with ATSI		7		7		7
Expenses:
Purchased power under PSA		625		452		444
Purchased power from TE		102		105		101
FESC support services		63		60		65
Other Income:
Interest income from ATSI		-		1		7
Interest income from FES and NGC		57		6		-

29

The Company is buying 150 MW of TE's Beaver Valley Unit 2 leased capacity entitlement. Purchased power expenses for this transaction were $102 million, $105 million and $101 million in 2006, 2005 and 2004, 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.

3. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees. The trusteed plans provide defined benefits based on years of service and compensation levels. FirstEnergy's funding policy is based on actuarial computations using the projected unit credit method. FirstEnergy made a $300 million voluntary cash contribution to its qualified pension plan on January 2, 2007 (Company's share was $25 million). Projections indicated that additional cash contributions will not be required before 2016.

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. During 2006, FirstEnergy amended the OPEB plan effective in 2008 to cap the monthly contribution for many of the retirees and their spouses receiving subsidized healthcare coverage. 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 its pension and OPEB plans. The fair value of the plan assets represents the actual market value as of December 31, 2006.

In December 2006, FirstEnergy adopted SFAS 158. This Statement requires an employer to recognize an asset or liability for the overfunded or underfunded status of their pension and other postretirement benefit plans. For a pension plan, the asset or liability is the difference between the fair value of the plan's assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan's assets and the accumulated postretirement benefit obligation. The Statement required employers to recognize all unrecognized prior service costs and credits and unrecognized actuarial gains and losses in AOCL, net of tax. Such amounts will be adjusted as they are subsequently recognized as components of net periodic benefit cost or income pursuant to the current recognition and amortization provisions. CEI's incremental impact of adopting SFAS 158 was a decrease of $135 million in pension assets, an increase of $39 million in pension liabilities and a decrease in AOCL of $104 million, net of tax.

30

With the exception of the Company's share of net pension (asset) liability at the end of year and net periodic pension expense, the following tables detail the Consolidated FirstEnergy pension plan and OPEB.

Obligations and Funded Status	Pension Benefits						Other Benefits
As of December 31	2006			2005			2006			2005
	(In millions)
Change in benefit obligation
Benefit obligation as of January 1	$	4,750		$	4,364		$	1,884		$	1,930
Service cost		83			77			34			40
Interest cost		266			254			105			111
Plan participants' contributions		-			-			20			18
Plan amendments		3			15			(620	)		(312	)
Medicare retiree drug subsidy		-			-			6			-
Actuarial (gain) loss		33			310			(119	)		197
Benefits paid		(274	)		(270	)		(109	)		(100	)
Benefit obligation as of December 31	$	4,861		$	4,750		$	1,201		$	1,884
Change in fair value of plan assets
Fair value of plan assets as of January 1	$	4,524		$	3,969		$	573		$	564
Actual return on plan assets		567			325			69			33
Company contribution		-			500			54			58
Plan participants' contribution		-			-			20			18
Benefits paid		(273	)		(270	)		(109	)		(100	)
Fair value of plan assets as of December 31	$	4,818		$	4,524		$	607		$	573
Funded status	$	(43	)	$	(226	)	$	(594	)	$	(1,311	)
Accumulated benefit obligation	$	4,447		$	4,327
Amounts Recognized in the Statement of
Financial Position
Noncurrent assets	$	-		$	1,023		$	-		$	-
Current liabilities		-			-			-			-
Noncurrent liabilities		(43	)		-			(594	)		(1,057	)
Net pension asset (liability) as of December 31	$	(43	)	$	1,023		$	(594	)	$	(1,057	)
Company's share of net pension asset (liability) at end of year	$	(13	)	$	139		$	(110	)	$	(83	)
Amounts Recognized in
Accumulated Other Comprehensive Income
Prior service cost (credit)	$	63		$	-		$	(1,190	)	$	-
Actuarial loss		982			-			702			-
Net amount recognized	$	1,045		$	-		$	(488	)	$	-
Assumptions Used to Determine
Benefit Obligations As of December 31
Discount rate		6.00	%		5.75	%		6.00	%		5.75	%
Rate of compensation increase		3.50	%		3.50	%
Allocation of Plan Assets
As of December 31
Asset Category
Equity securities		64	%		63	%		72	%		71	%
Debt securities		29			33			26			27
Real estate		5			2			1			-
Private equities		1			-			-			-
Cash		1			2			1			2
Total		100	%		100	%		100	%		100	%

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Estimated Items to Be Amortized in 2007 Net
Periodic Pension Cost from Accumulated	Pension		Other
Other Comprehensive Income	Benefits		Benefits
Prior service cost (credit)	$	10	$	(149)
Actuarial loss	$	41	$	45

	Pension Benefits									Other Benefits
Components of Net Periodic Benefit Costs	2006			2005			2004			2006			2005			2004
	(In millions)
Service cost	$	83		$	77		$	77		$	34		$	40		$	36
Interest cost		266			254			252			105			111			112
Expected return on plan assets		(396	)		(345	)		(286	)		(46	)		(45	)		(44	)
Amortization of prior service cost		10			8			9			(76	)		(45	)		(40	)
Recognized net actuarial loss		58			36			39			56			40			39
Net periodic cost	$	21		$	30		$	91		$	73		$	101		$	103
Company's share of net periodic cost	$	4		$	1		$	6		$	11		$	15		$	18
Weighted-Average Assumptions Used
to Determine Net Periodic Benefit Cost	Pension Benefits									Other Benefits
for Years Ended December 31		2006			2005			2004			2006			2005			2004
Discount rate		5.75	%		6.00	%		6.25	%		5.75	%		6.00	%		6.25	%
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	2006			2005
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)		2011-2013			2010-2012

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	$	6	$	(5	)
Effect on accumulated postretirement benefit obligation	$	33	$	(29	)

32

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

	Pension		Other
	Benefits		Benefits
	(In millions)
2007	$	247	$	91
2008		249		91
2009		256		94
2010		269		98
2011		280		101
Years 2012- 2016		1,606		537

4.FAIR VALUE OF FINANCIAL INSTRUMENTS:

  (A) 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 disclosed in the Consolidated Statements of Capitalization as of December 31:

	2006				2005
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Long-term debt	$	1,816	$	1,895	$	1,901	$	2,016
Subordinated debentures to affiliated trusts		103		105		103		140
	$	1,919	$	2,000	$	2,004	$	2,156

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.

  (B) INVESTMENTS-

Investments other than cash and cash equivalents include held-to-maturity securities and available-for-sale securities. The Company periodically evaluates its investments for other-than-temporary impairment. They first consider their intent and ability to hold the investment until recovery and then consider, among other factors, the duration and the extent to which the security's fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating investments for impairment. The following table provides the approximate fair value and related carrying amounts of investments excluding investments of $9 million for both 2006 and 2005 excluded by SFAS 107, "Disclosures about Fair Values of Financial Instruments", as of December 31:

	2006				2005
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Notes receivable	$	487	$	487	$	1,058	$	1,058
Debt securities:
-Corporate debt securities		3		5		3		40
-Lease obligation bonds		520		583		564		630
		523		588		567		670
	$	1,010	$	1,075	$	1,625	$	1,728

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The table above includes notes receivable, lease obligation bonds, and corporate debt. The fair value of notes receivables represents 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 and have maturity dates ranging from 2007 to 2025. The investments in lease obligation bonds and corporate debt are accounted for as held-to-maturity securities and the fair value is based on present value of the cash inflows based on the yield to maturity similar to the notes receivable. With maturity dates ranging from the 2007 to 2015.

The following table provides the amortized cost basis, unrealized gains and losses and fair values for the investments debt securities and lease obligation bonds above, which excludes the notes receivable:

	2006								2005
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
	(In millions)
Debt securities	$	523	$	65	$	-	$	588	$	567	$	103	$	-	$	670

Prior to their transfer to NGC in December 2005 (see Note 10), the Company's decommissioning trust investments were classified as available-for-sale. The Company has no securities held for trading purposes. The unrealized gains and losses applicable to the Company's decommissioning trusts were recognized in OCI in accordance with SFAS 115.

Proceeds from the sale of investments, realized gains and losses on those sales, and interest and dividend income for the three years ended December 31, 2006 were as follows:

		2005		2004
		(In millions)
Proceeds from sales	$	475	$	411
Realized gains		49		35
Realized losses		20		21
Interest and dividend income		12		11

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, 2006 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, 2006 are summarized as follows:

	2006		2005		2004
	(In millions)
Operating leases
Interest element	$	26.3	$	28.4	$	29.1
Other		48.2		40.9		29.4
Capital leases
Interest element		0.4		0.5		0.5
Other		0.6		0.5		0.5
Total rentals	$	75.5	$	70.3	$	59.5

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The future minimum lease payments as of December 31, 2006 are:

				Operating Leases
		Capital		Lease		Capital
		Leases		Payments		Trust		Net
		(In millions)
2007		$	1.0	$	62.3	$	48.2	$	14.1
2008			1.0		59.0		42.9		16.1
2009			1.0		60.7		46.1		14.6
2010			1.0		61.2		49.0		12.2
2011			1.0		57.9		49.0		8.9
Years thereafter			0.7		323.2		206.3		116.9
Total minimum lease payments			5.7	$	624.3	$	441.5	$	182.8
Interest portion			1.3
Present value of net minimum lease payments			4.4
	Less current portion		0.6
Noncurrent portion		$	3.8

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, 2006 the above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant totaled approximately $608 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 ($570 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 a VIE 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 lease obligation bonds 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 $177million ($9 million current) and $189 million ($12 million current) as of December 31, 2006 and December 31, 2005, 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 $955 million, 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 $97 million, that would not be payable if the casualty value payments are made.

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7. 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 was or 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.

8. 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 the Company's transition 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 equipment or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability entities may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future, which could require additional, material expenditures.

The EPACT provides for the creation of an ERO to establish and enforce reliability standards for the bulk power system, subject to FERC's review. On February 3, 2006, the FERC adopted a rule establishing certification requirements for the ERO, as well as regional entities envisioned to assume compliance monitoring and enforcement responsibility for the new reliability standards. The FERC issued an order on rehearing on March 30, 2006, providing certain clarifications and essentially affirming the rule.

The NERC has been preparing the implementation aspects of reorganizing its structure to meet the FERC's certification requirements for the ERO. The NERC made a filing with the FERC on April 4, 2006 to obtain certification as the ERO and to obtain FERC approval of pro forma delegation agreements with regional reliability organizations (regional entities). The new FERC rule referred to above, further provides for reorganizing regional entities that would replace the current regional councils and for rearranging their relationship with the ERO. The "regional entity" may be delegated authority by the ERO, subject to FERC approval, for compliance and enforcement of reliability standards adopted by the ERO and approved by the FERC. The ERO filing was noticed on April 7, 2006 and comments and reply comments were filed in May, June and July 2006. On July 20, 2006, the FERC certified the NERC as the ERO to implement the provisions of Section 215 of the Federal Power Act and directed the NERC to make compliance filings addressing governance and non-governance issues and the regional delegation agreements. On September 18, 2006 and October 18, 2006, NERC submitted compliance filings addressing the governance and non-governance issues identified in the FERC ERO Certification Order, dated July 20, 2006. On October 30, 2006, the FERC issued an order accepting most of NERC's governance filings. On January 18, 2007, the FERC issued an order largely accepting NERC's compliance filings addressing non-governance issues, subject to an additional compliance filing requirement.

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On April 4, 2006, NERC also submitted a filing with the FERC seeking approval of mandatory reliability standards, as well as for approval with the relevant Canadian authorities. These reliability standards are based, with some modifications and additions, on the current NERC Version 0 reliability standards. The reliability standards filing was subsequently evaluated by the FERC on May 11, 2006, leading to the FERC staff's release of a preliminary assessment that cited many deficiencies in the proposed reliability standards. The NERC and industry participants filed comments in response to the Staff's preliminary assessment. The FERC held a technical conference on the proposed reliability standards on July 6, 2006. The FERC issued a NOPR on the proposed reliability standards on October 20, 2006. In the NOPR, the FERC proposed to approve 83 of the 107 reliability standards and directed NERC to make technical improvements to 62 of the 83 standards approved. The 24 standards that were not approved remain pending at the FERC awaiting further clarification and filings by the NERC and regional entities. The FERC also provided additional clarification within the NOPR regarding the proposed application of final standards and guidance with regard to technical improvements of the standards. On November 15, 2006, NERC submitted several revised reliability standards and three new proposed reliability standards. Interested parties were provided the opportunity to comment on the NOPR (including the revised standards submitted by NERC in November) by January 3, 2007. Numerous parties, including FirstEnergy, filed comments on the NOPR on January 3, 2007. Mandatory reliability standards enforceable with penalties are expected to be in place by the summer of 2007. In a separate order issued October 24, 2006, the FERC approved NERC's 2007 budget and business plan subject to certain compliance filings.

On November 29, 2006, NERC submitted an additional compliance filing with the FERC regarding the Compliance Monitoring and Enforcement Program (CMEP) along with the proposed Delegation Agreements between the ERO and the regional reliability entities. The FERC provided opportunity for interested parties to comment on the CMEP by January 10, 2007. We, as well as other parties, moved to intervene and submitted responsive comments on January 10, 2007. This filing is pending before the FERC.

The ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils 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 on November 29, 2006 filed a proposed Delegation Agreement with NERC to obtain certification consistent with the final rule as a "regional entity" under the ERO. All of FirstEnergy's facilities are located within the ReliabilityFirst region.

On May 2, 2006, the NERC Board of Trustees adopted eight new cyber security standards that replaced interim standards put in place in the wake of the September 11, 2001 terrorist attacks, and thirteen additional reliability standards. The security standards became effective on June 1, 2006, and the remaining standards will become effective throughout 2006 and 2007. NERC filed these proposed standards with the FERC and relevant Canadian authorities for approval. The cyber security standards were not included in the October 20, 2006 NOPR and are being addressed in a separate FERC docket. On December 11, 2006, the FERC Staff provided its preliminary assessment of these proposed mandatory reliability standards and again cited various deficiencies in the proposed standards, providing interested parties with the opportunity to comment on the assessment by February 12, 2007.

FirstEnergy believes it is in compliance with all current NERC reliability standards. However, based upon a review of the October 20, 2006 NOPR, it appears that the FERC will adopt more strict reliability standards than those contained in the current NERC 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. If FirstEnergy is unable to meet the reliability standards for its bulk power system in the future, it could have a material adverse effect on FirstEnergy's and its subsidiaries' financial condition, results of operations and cash flows.

On October 21, 2003, the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to the PUCO's concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming the PUCO's order in all respects, except it remanded back to the PUCO the matter of ensuring the availability of sufficient means for customer participation in the marketplace. The RSP contained a provision that permitted the Ohio Companies to withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies have 30 days from the final order or decision to provide notice of termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding on Remand. In their Request, the Ohio Companies provided notice of termination to those provisions of the RSP subject to termination, subject to being withdrawn, and also set forth a framework for addressing the Supreme Court of Ohio's findings on customer participation. If the PUCO approves a resolution to the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies' termination will be withdrawn and considered to be null and void. On July 26, 2006, the PUCO issued an Entry directing the Ohio Companies to file a plan in a new docket to address the Court's concern. The Ohio Companies filed their RSP Remand CBP on September 29, 2006. Initial comments were filed on January 12, 2007 and reply comments were filed on January 29, 2007. In their reply comments the Ohio Companies described the highlights of a new tariff offering they would be willing to make available to customers that would allow customers to purchase renewable energy certificates associated with a renewable generation source, subject to PUCO approval. No further proceedings are scheduled at this time.

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The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP filed on September 9, 2005. Major provisions of the RCP include:

Maintaining the existing level of base distribution rates through April 30, 2009 for the Company;

Deferring and capitalizing for future recovery (over a 25-year period) with carrying charges certain distribution costs to be incurred during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three years;

Adjusting 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 the Company;

Reducing the deferred shopping incentive balances as of January 1, 2006 by up to $85 million for the Company by accelerating the application of the Company's accumulated cost of removal regulatory liability; and

Deferring and capitalizing (for recovery over a 25-year period) increased fuel costs above the amount collected through the Ohio Companies'  fuel recovery mechanism.

  

  On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies' RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. On January 10, 2006, the Ohio Companies filed a Motion for Clarification seeking clarity on a number of issues. On January 25, 2006, the PUCO issued an Entry on Rehearing granting in part, and denying in part, the Ohio Companies' previous requests and clarifying issues referred to above. The PUCO granted the Ohio Companies' requests to:

Recognize fuel and distribution deferrals commencing January 1, 2006;

Recognize distribution deferrals on a monthly basis prior to review by the PUCO Staff;

Clarify that the types of distribution expenditures included in the Supplemental Stipulation may be deferred; and

Clarify that distribution expenditures do not have to be 'accelerated' in order to be deferred.

The PUCO approved the Ohio Companies' methodology for determining distribution deferral amounts, but denied the Motion in that the PUCO Staff must verify the level of distribution expenditures contained in current rates, as opposed to simply accepting the amounts contained in the Ohio Companies' Motion. On February 3, 2006, several other parties filed applications for rehearing, which the PUCO denied on March 1, 2006. Two of these parties subsequently filed notices of appeal with the Supreme Court of Ohio. The Ohio Supreme Court scheduled this case for oral argument on February 27, 2007. On January 31, 2007, the Ohio Companies filed a stipulation which, among other matters and subject to PUCO approval, affirmed that the supplemental stipulation in the RCP would be implemented. This stipulation was approved by the PUCO on February 14, 2007.

On December 30, 2004, the Ohio Companies 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 Ohio Companies requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. The parties reached a settlement agreement that was approved by the PUCO on August 31, 2005. The incremental transmission and ancillary service revenues recovered from January 1 through June 30, 2006 were approximately $54 million. That amount included the recovery of a portion of the 2005 deferred MISO expenses as described below. On April 27, 2006, the Ohio Companies filed the annual update rider to determine revenues ($124 million) from July 2006 through June 2007. The filed rider went into effect on July 1, 2006.

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The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for the Ohio Companies 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 Ohio Companies to accrue carrying charges on the deferred balances. On August 31, 2005, the OCC appealed the PUCO's decision. On January 20, 2006, the OCC sought rehearing of the PUCO's approval of the recovery of deferred costs through the rider during the period January 1, 2006 through June 30, 2006. The PUCO denied the OCC's application on February 6, 2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. On March 27, 2006, the OCC filed a motion to consolidate this appeal with the deferral appeals discussed above and to postpone oral arguments in the deferral appeal until after all briefs are filed in this most recent appeal of the rider recovery mechanism. On March 20, 2006, the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of the Ohio Companies' case with a similar case involving Dayton Power & Light Company. Oral arguments were heard on May 10, 2006. On November 29, 2006, the Ohio Supreme Court issued its opinion upholding the PUCO's determination that the Ohio Companies may defer transmission and ancillary service related costs incurred on and after December 30, 2004. The Ohio Supreme Court also determined that the PUCO erred when it denied the OCC intervention, but further ruled that such error did not prejudice OCC and, therefore, the Ohio Supreme Court did not reverse or remand the PUCO on this ground. The Ohio Supreme Court also determined that the OCC's appeal was not premature. No party filed a motion for reconsideration with the Ohio Supreme Court.

On November 1, 2005, FES filed a power sales agreement for approval with the FERC. The 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 CBP results in a lower price for retail customers.

On December 29, 2005, the FERC issued an order setting the power sales agreement for hearing. The order criticized the Ohio CBP, and required FES to submit additional evidence in support of the reasonableness of the prices charged in the power sales agreement. On July 14, 2006, the Chief Judge granted the joint motion of FES and the Trial Staff to appoint a settlement judge in this proceeding and the procedural schedule was suspended pending settlement discussions among the parties. A settlement conference was held on September 5, 2006. FES, the Ohio Companies and the PUCO, along with other parties, reached an agreement to settle the case. The settlement was filed with the FERC on October 17, 2006, and was unopposed by the remaining parties, including the FERC Trial Staff. This settlement was accepted by the FERC on December 8, 2006.

The terms of the settlement provide for modification of the power supply agreement with FES. Under the power supply agreement, separate rates are established for the Ohio Companies' PLR requirements; special retail contract requirements, wholesale contract requirements, and interruptible buy-through retail load requirements. For their PLR and special retail contract requirements, the Ohio Companies will pay FES no more than the lower of (i) the sum of the retail generation charge, the rate stabilization charge, the fuel recovery mechanism charge, and FES' actual incremental fuel costs for such sales; or (ii) the wholesale price cap. Different wholesale price caps are imposed for PLR sales, special retail contracts, and wholesale contracts. The wholesale price for interruptible buy-through retail load requirements is limited to the actual spot price of power obtained by FES to provide this power. FES billed the Ohio Companies for the additional amount payable to FES for incremental fuel costs on power supplied during 2006. The total power supply cost billed by FES was lower in each case than the wholesale price caps specified in the settlement accepted by the FERC.

On February 15, 2007, MISO filed documents with the FERC to establish a market-based, competitive ancillary services market. MISO contends that the filing will integrate operating reserves into MISO's existing day-ahead and real-time settlements process, incorporate opportunity costs into these markets, address scarcity pricing through the implementation of a demand curve methodology, foster demand response in the provision of operating reserves, and provide for various efficiencies and optimization with regard to generation dispatch. The filing also proposes amendments to existing documents to provide for the transfer of balancing functions from existing local balancing authorities to MISO. MISO will then carry out this reliability function as the NERC-certified balancing authority for the MISO region. MISO is targeting implementation for the second or third quarter of 2008. The FERC has established March 23, 2007, as the date for interested parties to submit comments addressing the filing. The filing has not yet been fully evaluated to assess its impact on our operations.

On February 16, 2007, the FERC issued a final rule that revises its decade-old open access transmission regulations and policies. The FERC explained that the final rule is intended to strengthen non-discriminatory access to the transmission grid, facilitate FERC enforcement, and provide for a more open and coordinated transmission planning process. The final rule will not be effective until 60 days after publication in the Federal Register. The final rule has not yet been fully evaluated to assess its impact on our operations.

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9.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-

The Company has four million authorized and unissued shares of preferred stock having no par value.

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

(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)
2007	$	120
2008		221
2009		162
2010		18
2011		20

Included in the 2008 amount are $82 million for variable interest rate pollution control revenue bonds 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. This amount represents the next time 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 noncancelable municipal bond insurance policies of $60 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the policies, the Company is entitled to a credit against its obligation to repay that bond. For the pollution control revenue bonds issued in 2005, the Company pays annual fees of 0.29% of the amount of the policy to the insurer. The Company is obligated to reimburse the insurers 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, 2006, 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.

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10. ASSET RETIREMENT OBLIGATION:

The Company has recognized legal obligations under SFAS 143 and FIN 47. SFAS 143 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.

In May 2006, the Company sold its interest in the Ashtabula C Plant. As part of the transaction, the Company settled the $6 million ARO that had been established with the adoption of FIN 47.

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 13). As a result, only the ARO associated with the two coal ash disposal sites and the sale and leaseback arrangements remain with the Company.

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.

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 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 is immaterial.

The following table describes the changes to the ARO balances during 2006 and 2005.

	2006			2005
ARO Reconciliation	(In millions)
Balance at beginning of year	$	8		$	272
Liabilities settled		(6	)		-
Transfers to FGCO and NCG		-			(247	)
Accretion		-			17
Revisions in estimated cash flows		-			(41	)
FIN 47 ARO upon adoption		-			7
Balance at end of year	$	2		$	8

11. SHORT-TERM BORROWINGS:

Short-term borrowings outstanding as of December 31, 2006, consisted of $218 million of borrowings from affiliates. 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 0.15% on the amount of the entire finance limit. In June 2005, the CFC receivable financing structure was restructured from an off-balance sheet transaction to an on-balance sheet transaction. Under the new structure, any borrowings under the facility appear on CEI's consolidated balance sheet as short-term debt. The receivables financing agreement expires on December 5, 2007. 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. As of December 31, 2006, the facility was undrawn.

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On August 24, 2006, the Company, FirstEnergy, OE, Penn, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, have entered into a new $2.75 billion five-year revolving credit facility which replaced the prior $2 billion credit facility. Subject to specified conditions, FirstEnergy may request an increase in the total commitments available under the new facility up to a maximum of $3.25 billion. Borrowings under the facility are available to each Commitments under the new facility are available until August 24, 2011, unless the lenders agree, at the request of the Borrowers, to two additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each Borrower are subject to a specified sublimit, as well as applicable regulatory and other limitations. The Company's borrowing limit under the facility is $250 million subject to applicable regulatory approvals. The average interest rate on short-term borrowings outstanding as of December 31, 2006 and 2005 was 5.7% and 4.2%, respectively.

12. 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 become both probable and reasonably estimable.

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, 2006, 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 $1.8 million have been accrued through December 31, 2006.

(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 Web site (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. 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 is also 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 that could require additional material expenditures.

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FirstEnergy companies also are defending five separate complaint cases before the PUCO relating to the August 14, 2003 power outages. 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. Three other pending PUCO complaint cases were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of these three cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc., as well) for claims paid to insureds for damages 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. A sixth case involving the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003 was dismissed. On March 7, 2006, the PUCO issued a ruling, consolidating all of the pending outage cases for hearing; limiting the litigation to service-related claims by customers of the Ohio operating companies; dismissing FirstEnergy as a defendant; and ruling that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence. In response to a motion for rehearing filed by one of the claimants, the PUCO ruled on April 26, 2006 that the insurance company claimants, as insurers, may prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities that provide their service. The PUCO denied all other motions for rehearing. The plaintiffs in each case have since filed amended complaints and the named FirstEnergy companies have answered and also have filed a motion to dismiss each action. On September 27, 2006, the PUCO dismissed certain parties and claims and otherwise ordered the complaints to go forward to hearing. The cases have been set for hearing on October 16, 2007.

On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga County Common Pleas Court seeking reimbursement for claims paid to numerous insureds who allegedly suffered losses as a result of the August 14, 2003 outages. All of the insureds appear to be non-customers. The plaintiff insurance companies are the same claimants in one of the pending PUCO cases. FirstEnergy, the Ohio Companies and Penn were served on October 27, 2006. On January 18, 2007, the Court granted the Companies' motion to dismiss the case. It is unknown whether or not the matter will be further appealed. No estimate of potential liability is available for any of these cases.

The Company 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 Company. 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 the Company's 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, we were 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 now repealed PUHCA. Concurrent with this notification, we received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, we 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-related disclosures, which has been provided. We have cooperated fully with the informal inquiry and continue to do so with the formal investigation.

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 the Company's financial condition, results of operations and cash flows.

13.       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 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 the Company's leasehold interests in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.

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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.

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 the Company'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 the Company's outstanding pollution control debt. The timing of any refunding will be subject to market conditions and other factors.

On December 16, 2005, the Company 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 the Company's interest in associated decommissioning trust funds, other related assets and other liabilities associated with the transferred assets. In addition, the Company 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 the Company'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. In December 2006, the Company recorded purchase price adjustments totaling $195.9 million for the nuclear generation asset transfer to adjust intercompany notes and equity accounts to reflect a change in the agreed upon value for the asset retirement obligations that were assumed 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 8 - Regulatory Matters).

The following table provides the value of assets transferred in 2005 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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14. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS:

SFAS 159 - "The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115"

In February 2007, FASB issued SFAS 159, which provides companies with an option to report selected financial assets and liabilities at fair value. The Standard requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company's choice to use fair value on its earnings. The Standard also requires companies to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. This guidance does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS 157, Fair Value Measurements, and SFAS 107, Disclosures about Fair Value of Financial Instruments. The Company is currently evaluating the impact of this Statement on its financial statements.

SFAS 157 - "Fair Value Measurements"

In September 2006, the FASB issued SFAS 157, that establishes how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. This Statement addresses the need for increased consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. The key changes to current practice are: (1) the definition of fair value which focuses on an exit price rather than entry price; (2) the methods used to measure fair value such as emphasis that fair value is a market-based measurement, not an entity-specific measurement, as well as the inclusion of an adjustment for risk, restrictions and credit standing; and (3) the expanded disclosures about fair value measurements. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. The Company is currently evaluating the impact of this Statement on its financial statements.

FIN 48 - "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109"

In June 2006, the FASB issued FIN 48 which clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with FASB Statement No. 109, "Accounting for Income Taxes." This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken on a tax return. This interpretation also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and transition. The evaluation of a tax position in accordance with this interpretation will be a two-step process. The first step will determine if it is more likely than not that a tax position will be sustained upon examination and should therefore be recognized. The second step will measure a tax position that meets the more likely than not recognition threshold to determine the amount of benefit to recognize in the financial statements. This interpretation is effective for fiscal years beginning after December 15, 2006. The Company does not expect this Statement to have a material impact on its financial statements.

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15. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):

The following summarizes certain consolidated operating results by quarter for 2006 and 2005.

Three Months Ended	March 31, 2006			June 30, 2006			September 30, 2006			December 31, 2006
	(In millions)
Revenues	$	407.8		$	432.4		$	515.9		$	413.6
Expenses		283.5			280.1			375.6			303.9
Operating Income		124.3			152.3			140.3			109.7
Other Expense		(7.4	)		(3.5	)		(8.4	)		(12.6	)
Income Before Income Taxes		116.9			148.8			131.9			97.1
Income Taxes		44.5			57.7			48.5			38.0
Net Income	$	72.4		$	91.1		$	83.4		$	59.1

Three Months Ended	March 31, 2005			June 30, 2005			September 30, 2005		December 31, 2005
	(In millions)
Revenues	$	433.2		$	448.7		$	526.4	$	459.8
Expenses		382.3			355.8			354.1		340.1
Operating Income		50.9			92.9			172.3		119.7
Other Income (Expense)		(26.2	)		(17.0	)		6.4		(14.9	)
Income Before Income Taxes		24.7			75.9			178.7		104.8
Income Taxes		9.2			37.2			68.3		38.3
Income Before Cumulative Effect of a Change in Accounting Principle	$	15.5		$	38.7		$	110.4	$	66.5
Cumulative Effect of a Change in Accounting Principle (Net of Income Taxes)		-			-			-		(3.7)
Net Income	$	15.5		$	38.7		$	110.4	$	62.8
Earnings on Common Stock	$	12.6		$	38.7		$	110.4	$	62.8

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