THE TOLEDO EDISON COMPANY

2006 ANNUAL REPORT TO STOCKHOLDERS

The Toledo Edison 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 2,300 square miles in northwestern Ohio. The area it serves has a population of approximately 0.8 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	26-45

GLOSSARY OF TERMS

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

ATSI	American Transmission Systems, Inc., owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an affiliated Ohio electric utility
Centerior	Centerior Energy Corporation, former parent of CEI and TE, which merged with OE to form FirstEnergy on November 8, 1997
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
TE	The Toledo Edison Company
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
EPACT	Energy Policy Act of 2005
ERO	Electric Reliability Organization
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
FIN 46R	FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities"
FIN 47	FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"
FIN 48	FIN 48, "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109"
Fitch	Fitch Ratings, Ltd.
FMB	First Mortgage Bonds
FSP	FASB Staff Position
FSP SFAS 115-1 SFAS 124-1	FSP SFAS 115-1 and SFAS 124-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"
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
NERC	North American Electric Reliability Corporation
NOPR	Notice of Proposed Rulemaking
OCC	Office of the Ohio Consumers' Counsel
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

i

GLOSSARY OF TERMS, Cont'd.

RSP	Rate Stabilization Plan
RTC	Regulatory Transition Charge
S&P	Standard & Poor's Ratings Service
SEC	United States Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
SFAS 71	SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
SFAS 87	SFAS No. 87, "Employers' Accounting for Pensions"
SFAS 101	SFAS No. 101, "Accounting for Discontinuation of Application of SFAS 71"
SFAS 106	SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions"
SFAS 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 Pensions 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 Statements No. 115"
VIE	Variable Interest Entity

ii

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of The Toledo Edison 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 Toledo Edison Company and its subsidiary 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.

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 TOLEDO EDISON COMPANY
SELECTED FINANCIAL DATA
For the Years Ended December 31,	2006			2005			2004			2003			2002
	(Dollars in thousands)
GENERAL FINANCIAL INFORMATION:
Revenues	$	928,001		$	1,040,186		$	1,008,112		$	932,335		$	996,045
Operating Income	$	150,521		$	132,266		$	125,821		$	35,660		$	36,699
Net Income (Loss)	$	99,404		$	76,164		$	86,283		$	45,480		$	(5,142	)
Earnings (Loss) on Common Stock	$	89,995		$	68,369		$	77,439		$	36,642		$	(15,898	)
Total Assets	$	1,798,642		$	2,101,965		$	2,825,477		$	2,849,605		$	2,855,725
CAPITALIZATION AS OF DECEMBER 31:
Common Stockholder's Equity	$	481,415		$	863,426		$	835,327		$	749,521		$	681,195
Preferred Stock Not Subject to Mandatory
Redemption		-			96,000			126,000			126,000			126,000
Long-Term Debt		358,281			237,753			300,299			270,072			557,265
Total Capitalization	$	839,696		$	1,197,179		$	1,261,626		$	1,145,593		$	1,364,460
CAPITALIZATION RATIOS:
Common Stockholder's Equity		57.3	%		72.1	%		66.2	%		65.4	%		49.9	%
Preferred Stock Not Subject to Mandatory
Redemption		-			8.0			10.0			11.0			9.2
Long-Term Debt		42.7			19.9			23.8			23.6			40.9
Total Capitalization		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%
DISTRIBUTION KWH DELIVERIES (Millions):
Residential		2,430			2,543			2,316			2,312			2,427
Commercial		2,821			2,937			2,796			2,771			2,702
Industrial		5,139			5,110			5,006			5,097			5,280
Other		59			64			56			69			57
Total		10,449			10,654			10,174			10,249			10,466
CUSTOMERS SERVED:
Residential		275,869			275,226			273,800			270,258			272,474
Commercial		37,675			37,803			36,710			36,969			32,037
Industrial		218			224			211			215			1,883
Other		588			564			504			451			468
Total		314,350			313,817			311,225			307,893			306,862
NUMBER OF EMPLOYEES		420			431			414			446			508

2

THE TOLEDO EDISON COMPANY

MANAGEMENT'S DISCUSSION AND

ANALYSIS OF RESULTS OF OPERATIONS

AND FINANCIAL CONDITION

Forward-Looking Statements: This discussion includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms "anticipate," "potential," "expect," "believe," "estimate" and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, the continued ability 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 and Beaver Valley Unit 2, we have continued the generation KWH sales arrangement with FES and our Beaver Valley Unit 2 leased capacity sales arrangement with CEI, 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 Outlook - Regulatory Matters).

The effects on our results of operations in 2006 compared to 2005 from the generation asset transfers are summarized in the following table:

Intra-System Generation Asset Transfers-			Increase
Income Statement Effects			(Decrease)
			(In millions)
Revenues:
Non-nuclear generating units rent	(a	)	$	(12	)
Nuclear-generated KWH sales	(b	)		(131	)
Total - Revenues Effect				(143	)
Expenses:
Fuel costs - nuclear	(c	)		(21	)
Nuclear operating costs	(c	)		(101	)
Provision for depreciation	(d	)		(29	)
General taxes	(e	)		(6	)
Total - Expenses Effect				(157	)
Operating Income Effect				14
Other Income (expense):
Interest income from notes receivable	(f	)		16
Nuclear decommissioning trust earnings	(g	)		(22	)
Interest expense	(h	)		(16	)
Total - Other Income Effect				10
Income Before Income Taxes Effect				24
Income Taxes	(i	)		10
Net Income Effect			$	14
(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 and the elimination of interest on pollution control       notes redeemed in conjunction with the nuclear asset transfers.
(i)  Income tax effect of the above adjustments.

Results of Operations

Earnings on common stock increased to $90 million in 2006 from $68 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 $8 million primarily due to higher revenues and decreased amortization of regulatory assets, partially offset by increased purchased power costs.

Earnings on common stock decreased to $68 million in 2005 from $77 million in 2004. This decrease resulted primarily from higher nuclear and other operating costs, partially offset by higher operating revenues, lower purchased power costs and increased deferrals of new regulatory assets. 

4

 Revenues

Revenues decreased by $112 million or 10.8% in 2006 from 2005, primarily due to the generation asset transfer impact displayed in the table above. Excluding the effects of the generation asset transfers, revenues increased $31 million primarily due to a $145 million increase in retail generation sales revenues and a $35 million reduction in customer shopping incentives, partially offset by a $135 million decrease in distribution revenues and a $16 million decrease in non-affiliated wholesale sales.

Wholesale revenues from non-affiliates decreased 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.

Revenues increased by $32 million or 3.2% in 2005 from 2004. The higher revenues resulted from increased retail generation revenues of $45 million, partially offset by a $5 million decrease in distribution revenues, a $4 million decrease in wholesale sales revenue and an increase in shopping incentive credits of $4 million.

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

Changes in Generation KWH Sales	2006			2005
Increase (Decrease)
Electric Generation:
Retail		13.2	%		4.2	%
Wholesale*		(24.3	)%		2.3	%
Net Change in Generation Sales		(0.8	)%		3.1	%

Change in Generation Revenues	2006			2005
Increase (Decrease)	(In millions)
Retail Generation:
Residential	$	74		$	2
Commercial		48			5
Industrial		23			38
Total Retail Generation		145			45
Wholesale*		(16	)		(4	)
Net Increase in Generation Revenues	$	129		$	41

* The 2006 amount excludes impact of generation asset transfers related to nuclear-generated KWH sales.

Retail generation revenues increased in all customer sectors in 2006 compared to 2005 (as shown in the table above) due to higher unit prices and increased KWH sales. The higher unit prices for generation reflected the rate stabilization charge and the fuel cost recovery rider, both of which became effective in the first quarter of 2006 under provisions of the RSP and RCP. The increase in generation KWH sales (residential - 51.3%, commercial - 13.1% and industrial - 2.4%) primarily resulted from decreased customer shopping. Generation services provided by alternative suppliers as a percentage of total sales delivered in our franchise area decreased by: residential - 32.5 percentage points, commercial - 9.4 percentage points and industrial - 1.7 percentage points. The decreased shopping resulted from certain alternative energy suppliers exiting the northern Ohio market at the end of 2005.

Retail generation revenues increased in all customer sectors in 2005 compared to 2004. Industrial revenues increased as a result of higher unit prices and a slight increase in KWH sales of 1.5%. Higher KWH sales to industrial customers were partially offset by a slight increase in customer shopping. Generation services provided to industrial customers by alternative suppliers as a percent of total industrial sales delivered in our service area increased by 0.5 percentage points during 2005. Higher residential and commercial revenues resulted from increased KWH sales (6.0% and 11.1%, respectively), reflecting increased air conditioning loads due to the warmer summer weather and higher unit prices. The 2005 increase in commercial KWH sales reflected a 2.9 percentage point reduction in customer shopping, while the residential KWH sales increase was moderated by a 2.0 percentage point increase in customer shopping.

5

Changes in distribution KWH deliveries and revenues in 2006 and 2005 from the prior year are summarized in the following table.

Changes in Distribution KWH Deliveries	2006		2005
Increase (Decrease)
Distribution Deliveries:
Residential	(4.4	)%	9.8	%
Commercial	(4.0	)%	5.1	%
Industrial	0.6	%	2.1	%
Net Change in Distribution Deliveries	(1.9	)%	4.7	%

Changes in Distribution Revenues	2006				2005
Increase (Decrease)	(In millions)
Residential		$	(57	)		$	15
Commercial			(60	)			4
Industrial			(18	)			(26	)
Net Decrease in Distribution Revenues		$	(135	)		$	(7	)

The distribution revenue decreases for 2006 compared to the prior year shown in the table above primarily reflected lower unit prices in all customer sectors and decreased KWH deliveries to residential and commercial customers. The lower unit prices resulted from the completion of the generation-related transition cost recovery in 2005 under our transition plan, partially offset by increased transmission rates to recover MISO costs beginning in the first quarter of 2006 (see Outlook - Regulatory Matters). The lower KWH deliveries to residential and commercial customers in 2006 reflected the impact of milder weather in 2006 compared to 2005. KWH deliveries to industrial customers increased in 2006 due to increased sales to automotive and oil refinery customers.

The $7 million decrease in distribution revenues in 2005 was due to lower industrial revenues, partially offset by increases in residential and commercial revenues. The impact from lower industrial unit prices more than offset higher KWH sales in all customer classes.

Expenses

Total expenses decreased by $130 million in 2006 and increased by $26 million in 2005, compared with the prior year. The 2006 decrease was principally due to the generation asset transfer effects as 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	$	(2	)	$	8
Purchased power costs		72			(16	)
Nuclear operating costs		1			13
Other operating costs		(2	)		16
Provision for depreciation		-			5
Amortization of regulatory assets		(46	)		17
Deferral of new regulatory assets		4			(20	)
General taxes		-			3
Net increase in expenses	$	27		$	26

Higher purchased power costs in 2006 compared to 2005 primarily reflected an increase in KWH purchased to meet the higher retail generation sales requirements and higher unit prices under our power supply agreement with FES (see Outlook - Regulatory Matters).

Lower amortization of regulatory assets in 2006 reflected the completion of generation-related transition cost recovery under our transition plan, partially offset by the amortization of deferred MISO costs that are being recovered in 2006. The decrease in deferrals of new regulatory assets in 2006 primarily resulted from the termination of shopping incentive deferrals in 2006 ($37 million) and lower MISO transmission cost deferrals ($5 million), partially offset by deferred distribution costs ($24 million) and incremental fuel costs ($16 million) that began in 2006 under the RCP. The deferral of interest on the unamortized shopping incentive balances continues under the RCP.

6

Higher fuel costs in 2005 compared to 2004 resulted principally from increased fossil generation at the Mansfield Plant. Purchased power costs decreased in 2005, compared with 2004, due to a 4.1% decrease in unit costs and a 1.1% decrease in KWH purchased. Increased nuclear operating costs in 2005 were due to expenses associated with the 74-day refueling outage at the Perry Plant and the 25-day refueling outage at Beaver Valley Unit 2 in 2005 - there were no refueling outages in 2004. Other operating costs increased in 2005, compared to 2004, primarily due to the MISO Day 2 expenses that began April 1, 2005, partially offset by lower vegetation management expenses and employee benefit costs.

                        Depreciation charges increased by $5 million in 2005 compared to 2004 primarily due to property additions and the amortization of leasehold improvements. These increases were partially offset by lower depreciation on electric plant as a result of the non-nuclear generation asset transfer on October 24, 2005 and the effect of revised service life assumptions for fossil-fired generating plants (for the 2005 period prior to the asset transfer).

The increase in charges for amortization of regulatory assets in 2005 compared to 2004 reflected an increase in transition cost amortization. The higher deferrals of new regulatory assets in 2005 compared to 2004 were primarily due to shopping incentives ($4 million) and related interest ($3 million) in 2005 and the deferral of $12 million of MISO expenses and related interest that began in the second quarter of 2005.

       Other Income

Excluding the asset transfer effects shown above, other income decreased by $18 million primarily because of higher interest expense on borrowings from associated companies and fixed-rate securities and unamortized debt expense associated with the redemption of pollution control notes in 2006.

Interest expense decreased by $12 million in 2005 compared to 2004, reflecting redemptions and refinancing activity. In 2005, we refinanced $45 million of pollution control notes. An additional $91 million of pollution control notes were refinanced by NGC as part of the nuclear generation asset transfer.

Income Taxes

Excluding the effects of the generation asset transfer, income taxes decreased $24 million in 2006 primarily due to the absence of approximately $18 million of income tax charges from the implementation of Ohio tax legislation changes in the second quarter of 2005.

Income taxes increased $22 million in 2005 primarily due to Ohio deferred tax adjustments and an increase in taxable income. 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 replaced 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 $18 million, which was partially offset by the initial phase-out of the Ohio income-based franchise tax, which reduced income taxes by approximately $1 million in 2005.

Preferred Stock Dividend Requirements

        Higher preferred stock dividend requirements in 2006 compared to 2005 were due to $5 million of premiums paid in connection with the optional redemption of preferred stock. In 2006 and 2005, we redeemed $96 million and $30 million of preferred stock, respectively. 

Capital Resources and Liquidity

Our cash requirements in 2006 for operating expenses and construction expenditures were met with a combination of cash from operations, funds from the capital markets and short-term credit arrangements. During 2007, we expect to meet our contractual obligations primarily with cash from operations. Borrowing capacity under our credit facilities is available to manage our working capital requirements. In subsequent years, we expect to use a combination of cash from operations and funds from the capital markets.

7

Changes in Cash Position

As of December 31, 2006, we had $22,000 of cash and cash equivalents, compared with $15,000 as of December 31, 2005. The major changes in these balances are summarized below.

Cash Flows From Operating Activities

Net cash provided from operating activities was $149 million in 2006, $156 million in 2005 and $183 million in 2004, summarized as follows:

Operating Cash Flows	2006			2005			2004
	(In millions)
Net income	$	99		$	76		$	86
Net non-cash charges (credits)		(1	)		135			154
Pension trust contribution*		3			(14	)		(8	)
Working capital and other		48			(41	)		(49	)
Net cash provided from operating activities	$	149		$	156		$	183

* Pension trust contributions in 2005 and 2004 are net of $6 million and $5 million of related current year cash income tax benefits, respectively. The $3 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 decreased $7 million in 2006 from 2005 as a result of a $136 million decrease in net non-cash charges, partially offset by a $23 million increase in net income, a $3 million tax benefit in 2006 relating to a January 2007 pension contribution, the absence in 2006 of the pension trust contribution in 2005, and an $89 million increase from changes in working capital and other. The changes in net income and non-cash charges are described above under "Results of Operations." The increase in cash provided from working capital was primarily due to an $85 million decrease in cash outflows for accounts payable.

Net cash provided from operating activities decreased $27 million in 2005 from 2004 as a result of a $10 million decrease in net income, a $19 million decrease in net non-cash charges (see "Results of Operations") and a $6 million increase in after-tax voluntary pension trust contributions, partially offset by an $8 million increase from changes in working capital and other. The increase in cash provided from working capital and other was primarily due to $38 million of funds received in 2005 for prepaid electric service (under the three-year Energy for Education Program with the Ohio Schools Council), partially offset by increased cash outflows for accounts payable of $22 million.

Cash Flows From Financing Activities

In 2006, 2005 and 2004, net cash used for financing activities of $248 million, $211 million and $94 million, respectively, primarily reflected the new issues and redemptions shown below:

Securities Issued or Redeemed	2006		2005			2004
	(In millions)
New Issues:
Unsecured Notes	$	297	$	-		$	-
Pollution Control Notes		-		45			104
	$	297	$	45		$	104
Redemptions:
Common Stock	$	225	$	-		$	-
Preferred Stock		96		30			-
Pollution Control Notes		203		136			-
Secured Notes		-		-			261
Other, principally redemption premiums		5		3			1
	$	529	$	169		$	262
Short-term borrowings (repayments), net	$	63	$	(9	)	$	74

8

Net cash used for financing activities increased $37 million in 2006 from 2005, primarily from a $36 million net increase in securities redemptions as shown above. Net cash used for financing activities increased $117 million in 2005 from 2004. The increase primarily resulted from a net increase of $49 million of net securities redemptions shown above and a $70 million increase in common stock dividends to FirstEnergy in 2005.

We had $101 million of cash and temporary investments (which include short-term notes receivable from associated companies) and approximately $154 million of short-term indebtedness as of December 31, 2006. We have authorization from the PUCO to incur short-term debt of up to $500 million through the bank facility and the utility money pool described below.

As of December 31, 2006, we had the capability to issue $786 million of additional FMB on the basis of property additions and retired bonds under the terms of our mortgage indenture. Our issuance of FMB is also subject to a provision of our senior note indenture generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, this provision would permit us to incur additional secured debt not otherwise permitted by a specified exception of up to $125 million. As a result of our redeeming all remaining outstanding preferred stock in December 2006, our applicable earnings coverage test is inoperative. In the event that we would issue preferred stock in the future, the applicable earnings coverage test will govern the amount of additional preferred stock that we may issue.

On August 24, 2006, we, FirstEnergy, OE, Penn, CEI, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, 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 approval.

Under the revolving credit facility, borrowers may request the issuance of LOCs expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under the facility and against the applicable borrower's borrowing sublimit.

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 53%.

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

    We have the ability to borrow from our regulated affiliates and FirstEnergy to meet our short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in 2006 was 5.22%.

                  Our access to capital markets and costs of financing are dependent on the ratings of our securities and the securities of FirstEnergy. The following table shows securities ratings as of February 2, 2007. The ratings outlook from S&P on all 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
TE	Senior secured	BBB	Baa2	BBB
	Senior unsecured	BBB-	Baa3	BBB-

9

   On January 20, 2006, we redeemed all 1.2 million of our outstanding shares of Adjustable Rate Series B preferred stock at $25.00 per share, plus accrued dividends to the date of redemption.

On November 18, 2006, we issued $300 million of 6.15% senior unsecured notes due 2037. The majority of the proceeds from this offering were used to repurchase $225 million of our common stock from FirstEnergy. The remainder of the proceeds was used to redeem $66 million of our preferred stock in December 2006.

In April and December of 2006, pollution control notes totaling $203 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 $59 million of remaining pollution control notes are subject to transfer.

Cash Flows From Investing Activities

Net cash provided from investing activities increased to $99 million in 2006 from $55 million in 2005. This change was primarily due to reductions of $28 million in net activity for the nuclear decommissioning trust funds and $11 million in property additions, both due to the generation asset transfers in the fourth quarter of 2005, and a net increase of $7 million from loan activity with associated companies.

Net cash provided from investing activities increased to $55 million in 2005 from a net use of cash for investing activities of $91 million in 2004. This change was primarily due to increased loan activity with associated companies. The $552 million increase in collection of long-term notes receivable in 2005 included $429 million from NGC and $123 million from FGCO. The $123 million received from FGCO related to a balloon payment received in May 2005 for the gas-fired combustion turbines sold in 2001. This increase in collection from associated companies was partially offset by $409 million in loan payments to the money pool, compared to $7 million in loan payments received from associated companies in 2004.

                        Our capital spending for the period 2007-2011 is expected to be nearly $325 million, of which approximately $64 million applies to 2007. The capital spending is primarily for property additions supporting the distribution of electricity. In addition, there is capital spending for the leasehold interests in certain generating plants retained after the generation asset transfers.

Contractual Obligations

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

					2008-		2010-
Contractual Obligations	Total		2007		2009		2011		Thereafter
	(In millions)
Long-term debt (1)	$	389	$	30	$	-	$	-	$	359
Short-term borrowings		154		154		-		-		-
Interest on long-term debt		627		23		42		42		520
Operating leases (2)		781		79		149		142		411
Pension funding (3)		8		8		-		-		-
Purchases (4)		438		35		107		119		177
Total	$	2,397	$	329	$	298	$	303	$	1,467

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

⁽²⁾ Operating lease payments are net of capital trust receipts of $250.8 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.

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Off-Balance Sheet Arrangements

Obligations not included on our Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley Unit 2, which are 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 $503 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 and debt obligations:

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	$	9		$	15		$	12		$	19		$	21		$	291		$	367		$	395
Average interest rate		7.7	%		7.7	%		7.7	%		7.7	%		7.7	%		6.1	%		6.4	%
Liabilities
Long-term Debt:
Fixed rate	$	30														$	314		$	344		$	343
Average interest rate		7.1	%														6.1	%		6.2	%
Variable rate																$	45		$	45		$	45
Average interest rate																	3.8	%		3.8	%
Short-term Borrowings	$	154																	$	154		$	154
Average interest rate		5.4	%																	5.4	%

Outlook

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

Regulatory Matters

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

11

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 December 31, 2008;

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, 2008;

Reducing our deferred shopping incentive balances as of January 1, 2006 by up to $45 million by accelerating the application of our accumulated cost of removal regulatory liability; and

Recovering increased fuel costs (compared to a 2002 baseline) of up to $75 million, $77 million, and $79 million, in 2006, 2007, and 2008, respectively, from all of OE's and our distribution and transmission customers through a fuel recovery mechanism. We may defer and capitalize (for recovery over a 25-year period) increased fuel costs above the amount collected through the fuel recovery mechanism.

The following table provides our estimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) for the remaining years of the RCP:

Period	Amortization
	(In millions)
2007	$	93
2008		119
Total Amortization	$	212

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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.

13

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.

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 $2.7 million as of December 31, 2006.

14

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

Other Legal Proceedings

Power Outage and Related Litigation-

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force's final report in April 2004 on the outages 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 FirstEnergy's 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 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 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(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

Critical Accounting Policies

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

Regulatory Accounting

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

Revenue Recognition

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

Pension and Other Postretirement Benefits Accounting

Our reported costs of providing non-contributory 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 OCI. 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. FirstLEnergy's underfunded status as of 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. Due to recent declines in corporate bond yields and interest rates in general, we reduced 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 $8 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.

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 TE's portion of pension and OPEB costs from changes in key assumptions are as follows:

Increase in Costs from Adverse Changes in Key Assumptions
Assumption	Adverse Change			Pension		OPEB		Total
				(In millions)
Discount rate		Decrease by 0.25	%	$	0.4	$	0.1	$	0.5
Long-term return on assets		Decrease by 0.25	%	$	0.4	$	-	$	0.4
Health care trend rate		Increase by 1	%		na	$	0.3	$	0.3

Ohio Transition Cost Amortization

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

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 judgement about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment.

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 $501 million 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 TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2006			2005			2004
	(In thousands)
REVENUES (Note 2(H)):
Electric sales	$	899,930		$	1,011,239		$	979,954
Excise tax collections		28,071			28,947			28,158
		928,001			1,040,186			1,008,112
EXPENSES (Note 2(H)):
Fuel		36,313			58,897			50,892
Purchased power		368,654			296,720			312,867
Nuclear operating costs		81,845			181,410			168,401
Other operating costs		166,403			168,522			152,879
Provision for depreciation		33,310			62,486			57,948
Amortization of regulatory assets		95,032			141,343			123,858
Deferral of new regulatory assets		(54,946	)		(58,566	)		(38,696	)
General taxes		50,869			57,108			54,142
Total expenses		777,480			907,920			882,291
OPERATING INCOME		150,521			132,266			125,821
OTHER INCOME (EXPENSE) (Note 2(H)):
Investment income		38,187			49,440			45,993
Miscellaneous expense		(7,379	)		(10,587	)		(3,438	)
Interest expense		(23,179	)		(21,489	)		(33,439	)
Capitalized interest		1,123			465			3,696
Total other income		8,752			17,829			12,812
INCOME BEFORE INCOME TAXES		159,273			150,095			138,633
INCOME TAXES		59,869			73,931			52,350
NET INCOME		99,404			76,164			86,283
PREFERRED STOCK DIVIDEND REQUIREMENTS		9,409			7,795			8,844
EARNINGS ON COMMON STOCK	$	89,995		$	68,369		$	77,439
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

20

THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31,	2006		2005
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	22	$	15
Receivables-
Customers		772		2,209
Associated companies		13,940		16,311
Other (less accumulated provision of $430,000 for
uncollectible accounts in 2006)		3,831		6,410
Notes receivable from associated companies		100,545		48,349
Prepayments and other		851		1,059
		119,961		74,353
UTILITY PLANT:
In service		894,888		824,677
Less - Accumulated provision for depreciation		394,225		372,845
		500,663		451,832
Construction work in progress		16,479		33,920
		517,142		485,752
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies		128,858		436,178
Investment in lessor notes		169,493		178,798
Nuclear plant decommissioning trusts		61,094		59,209
Other		1,871		1,781
		361,316		675,966
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		500,576		501,022
Regulatory assets		247,595		287,095
Prepaid pension costs (Note 3)		-		35,566
Property taxes		22,010		18,047
Other		30,042		24,164
		800,223		865,894
	$	1,798,642	$	2,101,965
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	30,000	$	53,650
Accounts payable-
Associated companies		84,884		46,386
Other		4,021		2,672
Notes payable to associated companies		153,567		64,689
Accrued taxes		47,318		49,344
Lease market valuation liability		24,600		24,600
Other		37,551		40,049
		381,941		281,390
CAPITALIZATION (See Statements of Capitalization):
Common stockholder's equity		481,415		863,426
Preferred stock		-		96,000
Long-term debt		358,281		237,753
		839,696		1,197,179
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		161,024		221,149
Accumulated deferred investment tax credits		11,014		11,824
Lease market valuation liability		218,800		243,400
Retirement benefits		77,902		40,353
Asset retirement obligations		26,543		24,836
Deferred revenues - electric service programs		23,546		32,606
Other		58,176		49,228
		577,005		623,396
COMMITMENTS AND CONTINGENCIES (Notes 5 and 12)
	$	1,798,642	$	2,101,965
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.

21

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
				Shares Outstanding		Dollars in Thousands
As of December 31,				2006	2005	2006		2005
COMMON STOCKHOLDER'S EQUITY:
		Common stock, $5 par value, 60,000,000 shares authorized		29,402,054	39,133,887	$            147,010		$            195,670
		Other paid-in capital				166,786		473,638
		Accumulated other comprehensive income (Note 2(F))				(36,804	)	4,690
		Retained earnings (Note 9(A))				204,423		189,428
			Total			481,415		863,426
PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION (Note 9(B)):
	Cumulative, $100 par value, 3,000,000 shares authorized-
		$4.25		-	160,000	-		16,000
		$4.56		-	50,000	-		5,000
		$4.25		-	100,000	-		10,000
			Total	-	310,000	-		31,000
	Cumulative, $25 par value, 12,000,000 shares authorized-
		$2.365		-	1,400,000	-		35,000
		Adjustable Series B		-	1,200,000	-		30,000
			Total	-	2,600,000	-		65,000
			Total Preferred Stock	-	2,910,000	-		96,000
LONG-TERM DEBT (Note 9(C)):
	Secured notes-
		7.130% due 2007				30,000		30,000
	*	3.050% due 2024				-		67,300
		6.100% due 2027				10,100		10,100
		5.375% due 2028				3,751		3,751
	*	3.400% due 2033				-		30,900
	*	3.130% due 2033				-		20,200
	*	3.150% due 2033				-		30,500
	*	3.750% due 2035				45,000		45,000
			Total			88,851		237,751
	Unsecured notes-
	*	3.540% due 2030				-		34,850
	*	3.620% due 2033				-		18,800
		6.150% due 2037				300,000		-
			Total			300,000		53,650
	Net unamortized premium (discount) on debt					(570	)	2
	Long-term debt due within one year					(30,000	)	(53,650	)
			Total long-term debt			358,281		237,753
TOTAL CAPITALIZATION						$            839,696		$         1,197,179
* Denotes variable-rate issue with applicable year-end interest rate shown.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

22

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
													Accumulated
										Other			Other
	Comprehensive			Number			Par			Paid-In			Comprehensive			Retained
	Income			of Shares			Value			Capital			Income (Loss)			Earnings
	(Dollars in thousands)
Balance, January 1, 2004					39,133,887		$	195,670		$	428,559		$	11,672		$	113,620
Net income	$	86,283															86,283
Unrealized gain on investments, net
of $5,246,000 of income taxes		7,253												7,253
Minimum liability for unfunded retirement benefits,
net of $717,000 of income taxes		1,114												1,114
Comprehensive income	$	94,650
Cash dividends on preferred stock																	(8,844	)
Balance, December 31, 2004					39,133,887			195,670			428,559			20,039			191,059
Net income	$	76,164															76,164
Unrealized loss on investments, net
of $16,884,000 of income tax benefits		(23,654	)											(23,654	)
Minimum liability for unfunded retirement benefits,
net of $5,836,000 of income taxes		8,305												8,305
Comprehensive income	$	60,815
Affiliated company asset transfers											45,060
Restricted stock units											19
Cash dividends on preferred stock																	(7,795	)
Cash dividends on common stock																	(70,000	)
Balance, December 31, 2005					39,133,887			195,670			473,638			4,690			189,428
Net income	$	99,404															99,404
Unrealized gain on investments, net
of $211,000 of income taxes		462												462
Comprehensive income	$	99,866
Net liability for unfunded retirement benefits
due to the implementation of SFAS 158, net
of $26,929,000 of income tax benefits														(41,956	)
Affiliated company asset transfers (see Note 13)											(130,571	)
Repurchase of common stock					(9,731,833	)		(48,660	)		(176,341	)
Preferred stock redemption premiums																	(4,840	)
Restricted stock units											38
Stock based compensation											22
Cash dividends on preferred stock																	(4,569	)
Cash dividends on common stock																	(75,000	)
Balance, December 31, 2006					29,402,054		$	147,010		$	166,786		$	(36,804	)	$	204,423

CONSOLIDATED STATEMENTS OF PREFERRED STOCK
	Not Subject to
	Mandatory Redemption
	Number			Carrying
	of Shares			Value
	(Dollars in thousands)
Balance, January 1, 2004		4,110,000		$	126,000
Balance, December 31, 2004		4,110,000			126,000
Redemptions-
Adjustable Series A		(1,200,000	)		(30,000	)
Balance, December 31, 2005		2,910,000			96,000
Redemptions-
$4.25 Series		(160,000	)		(16,000	)
$4.56 Series		(50,000	)		(5,000	)
$4.25 Series		(100,000	)		(10,000	)
$2.365 Series		(1,400,000	)		(35,000	)
Adjustable Series B		(1,200,000	)		(30,000	)
Balance, December 31, 2006		-		$	-
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

23

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,	2006			2005			2004
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	99,404		$	76,164		$	86,283
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		33,310			62,486			57,948
Amortization of regulatory assets		95,032			141,343			123,858
Deferral of new regulatory assets		(54,946	)		(58,566	)		(38,696	)
Nuclear fuel and capital lease amortization		-			18,463			25,034
Deferred rents and lease market valuation liability		(32,925	)		(30,088	)		(23,121	)
Deferred income taxes and investment tax credits, net		(37,133	)		(6,519	)		6,123
Accrued compensation and retirement benefits		4,415			5,396			6,963
Pension trust contribution		-			(19,933	)		(12,572	)
Tax refund related to pre-merger period		-			8,164			-
Decrease (increase) in operating assets-
Receivables		6,387			10,813			10,228
Materials and supplies		-			(3,210	)		(5,133	)
Prepayments and other current assets		208			91			5,554
Increase (decrease) in operating liabilities-
Accounts payable		39,847			(45,416	)		(23,398	)
Accrued taxes		(2,026	)		2,387			(8,647	)
Accrued interest		1,899			(1,557	)		(9,080	)
Electric service prepayment programs		(9,060	)		32,605			-
Other		4,640			(36,939	)		(18,438	)
Net cash provided from operating activities		149,052			155,684			182,906
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		296,663			45,000			103,500
Short-term borrowings, net		62,909			-			73,565
Redemptions and Repayments-
Common stock		(225,000	)		-			-
Preferred stock		(100,840	)		(30,000	)		-
Long-term debt		(202,550	)		(138,859	)		(262,162	)
Short-term borrowings, net		-			(8,996	)		-
Dividend Payments-
Common stock		(75,000	)		(70,000	)		-
Preferred stock		(4,569	)		(7,795	)		(8,844	)
Net cash used for financing activities		(248,387	)		(210,650	)		(93,941	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(61,232	)		(71,976	)		(64,629	)
Loan repayments from (loans to) associated companies, net		(52,178	)		(409,409	)		7,081
Collection of principal on long-term notes receivable		202,787			552,613			203
Investments in lessor notes (Note 5)		9,305			11,894			10,246
Proceeds from nuclear decommissioning trust fund sales		52,872			366,406			339,340
Investments in nuclear decommissioning trust funds		(53,138	)		(394,947	)		(367,881	)
Other		926			385			(15,547	)
Net cash provided from (used for) investing activities		99,342			54,966			(91,187	)
Net change in cash and cash equivalents		7			-			(2,222	)
Cash and cash equivalents at beginning of year		15			15			2,237
Cash and cash equivalents at end of year	$	22		$	15		$	15
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	17,785		$	29,709		$	40,082
Income taxes	$	95,753		$	78,265		$	53,728
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

24

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF TAXES
For the Years Ended December 31,	2006			2005			2004
	(In thousands)
GENERAL TAXES:
Ohio kilowatt-hour excise*	$	28,071		$	28,947		$	28,158
Real and personal property		20,078			25,030			23,559
Social security and unemployment		2,195			2,365			2,089
Other		525			766			336
Total general taxes	$	50,869		$	57,108		$	54,142
PROVISION FOR INCOME TAXES:
Currently payable-
Federal	$	82,971		$	61,914		$	34,587
State		14,031			18,535			11,640
		97,002			80,449			46,227
Deferred, net-
Federal		(34,776	)		(18,994	)		7,156
State		(1,547	)		14,875			1,064
		(36,323	)		(4,119	)		8,220
Investment tax credit amortization		(810	)		(2,399	)		(2,097	)
Total provision for income taxes	$	59,869		$	73,931		$	52,350
RECONCILIATION OF FEDERAL INCOME TAX
EXPENSE AT STATUTORY RATE TO TOTAL
PROVISION FOR INCOME TAXES:
Book income before provision for income taxes	$	159,273		$	150,095		$	138,633
Federal income tax expense at statutory rate	$	55,745		$	52,533		$	48,522
Increases (reductions) in taxes resulting from-
State income taxes, net of federal income tax benefit		8,115			21,716			8,258
Amortization of investment tax credits		(810	)		(2,399	)		(2,097	)
Amortization of tax regulatory assets		(1,138	)		(2,841	)		(2,492	)
Other, net		(2,043	)		4,922			159
Total provision for income taxes	$	59,869		$	73,931		$	52,350
ACCUMULATED DEFERRED INCOME TAXES AS OF
DECEMBER 31:
Property basis differences	$	243,410		$	229,430		$	216,933
Regulatory transition charge		33,408			54,719			101,190
Asset retirement obligations		4,437			-			14,703
Unamortized investment tax credits		(3,493	)		(3,785	)		(9,606	)
Deferred gain on asset sales to affiliated companies		10,038			10,893			11,111
Other comprehensive income		(23,683	)		3,036			14,084
Above market leases		(96,112	)		(104,998	)		(120,078	)
Retirement benefits		7,808			6,527			41
Deferred customer shopping incentive		18,399			43,926			36,628
Other		(33,188	)		(18,599	)		(43,056	)
Net deferred income tax liability	$	161,024		$	221,149		$	221,950
* 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 TE (Company) and its 90% owned subsidiary, TECC. TECC was formed in 1997 to make equity investments in a business trust in connection with financing related to the Bruce Mansfield Plant sale and leaseback transaction (see Note 5). CEI, an affiliate, has a 10% interest in TECC. The Company is a wholly owned subsidiary of FirstEnergy. FirstEnergy also holds directly all of the issued and outstanding common shares of its other principal electric utility operating subsidiaries, including CEI, OE, 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 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 will continue 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 remain regulated; accordingly, it is appropriate that the Company continues the application of SFAS 71 to those operations.

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

	2006			2005
	(In millions)
Regulatory transition costs	$	134		$	191
Customer shopping incentives		61			132
Distribution costs -- RCP		24			-
Fuel costs -RCP		17			-
Liabilities to customers - income taxes		(4	)		(5	)
Gain on reacquired debt		(3	)		(4	)
Employee postretirement benefit costs		5			6
MISO transmission costs		16			12
Asset removal costs		(5	)		(47	)
Other		3			2
Total	$	248		$	287

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 balances ($132 million as of December 31, 2005) were reduced on January 1, 2006 by $45 million by accelerating the application of the Company's accumulated cost of removal regulatory liability against the Extended RTC balances. In accordance with the RCP, the recovery periods for the aggregate of the regulatory transition costs and the Extended RTC amounts were adjusted so that recovery of these aggregate amounts through the Company's RTC rate component began on January 1, 2006, with full recovery expected to be completed as of December 31, 2008. At the end of the recovery period, any remaining unamortized regulatory transition costs and Extended RTC balances will be eliminated, first, by applying any remaining cost of removal regulatory liability balances; any remaining regulatory transition costs and Extended RTC balances would be written off. 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 Ohio Companies 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 is equal to the related revenue recovery that is recognized. The following table provides the estimated net amortization of regulatory transition costs and Extended RTC amounts (including associated carrying charges) for the remaining years of the RCP:

Period	Amortization
	(In millions)
2007	$	93
2008		119
Total Amortization	$	212

(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 historical customer usage, load profiles, estimated 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.

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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 billed were $1 million and $2 million as of December 31, 2006 and 2005, respectively. There were no unbilled receivables as of December 31, 2006 and 2005.

The Company and CEI sell substantially all of their retail customer receivables to CFC, a wholly owned subsidiary of CEI. 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.

(D) UTILITY PLANT AND DEPRECIATION-

Utility plant reflects original cost of construction (except for the Company's leasehold interests in Beaver Valley Unit 2 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 3.8% in 2006, 3.1% 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. The impairment analysis includes a significant source of cash representing the Company's recovery of transition costs as described above under "Regulatory Matters." The Company estimates that completion of transition cost recovery will not result in an impairment of goodwill. As of December 31, 2006, the Company had approximately $501 million 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.

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Investments-

At the end of each reporting period, the Company evaluates its investments for impairment. In accordance with SFAS 115 and FSP SFAS 115-1 and SFAS 124-1, investments classified as available-for-sale securities are evaluated to determine whether a decline in fair value below the cost basis is other than temporary. The Company first considers its intent and ability to hold the investment until recovery and then considers, 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. If the decline in fair value is determined to be other than temporary, the cost basis of the investment is written down to fair value. Upon adoption of FSP SFAS 115-1 and SFAS 124-1, the Company began recognizing in earnings the unrealized losses on available-for-sale securities held in the nuclear decommissioning trusts as the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of the other-than-temporary impairment. The fair value and unrealized gains and losses of the Company's investments are disclosed in Note 4(C).

(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 $42 million and unrealized gains on investments in securities available for sale of $5 million. As of December 31, 2005, accumulated other comprehensive income consisted of unrealized gains on investments in securities available for sale of $5 million.

(G)   INCOME TAXES-

Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. The Company records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax 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 the Company recognizing any tax losses or credits it contributed to the consolidated return (see Note 7 for Ohio Tax Legislation discussion).

(H)   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, CEI, 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 companies transactions are as follows:

	2006		2005		2004
	(In millions)
Revenues:
PSA revenues from FES	$	68	$	195	$	204
Generating units rent from FES		-		12		15
Electric sales to CEI		102		105		101
Ground lease with ATSI		2		2		2
Expenses:
Purchased power under PSA		363		295		311
FESC support services		37		34		36
Other Income:
Interest income from ATSI		3		3		3
Interest income from FES		15		4		10
Interest income from Shippingport (Note 6)		14		15		16

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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.

The Company is selling 150 megawatts of its Beaver Valley Unit 2 leased capacity entitlement to CEI. Operating revenues for this transaction were $102 million, $105 million and $101 million in 2006, 2005 and 2004, respectively. This sale agreement is expected to continue through the end of the lease period (see Note 5).

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 $8 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 employers 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. TE's incremental impact of adopting SFAS 158 was a decrease of $35 million in pension assets, an increase of $34 million in pension liabilities and a decrease in AOCL of $42 million, net of tax.

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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.

	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	$	(3	)	$	36		$	(74	)	$	(40	)
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
	(In millions)
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	$	1		$	1		$	3		$	8		$	9		$	7
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	)

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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-

All borrowings with initial maturities of less than one year are defined as financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value. The following table provides the approximate fair value and related carrying amounts of long-term debt as 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	$	389	$	388	$	291	$	293

The fair value of long-term debt reflects 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-

The following table provides the approximate fair value and related carrying amounts of investments excluding nuclear decommissioning trust funds and investments of $2 million 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	$	298	$	327	$	615	$	645

  The table above represents notes receivable. 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 2040.

(C) NUCLEAR DECOMMISSIONING TRUST FUND INVESTMENTS-

Nuclear decommissioning trust investments are classified as available-for-sale securities. As part of the intra-system nuclear generation asset transfer in the fourth quarter of 2005, the Company transferred its decommissioning trust investments to NGC with the exception of a portion related to the leasehold interests in Beaver Valley Unit 2 retained by the Company. The Company has no securities held for trading purposes. Upon adoption of FSP SFAS 115-1 and SFAS 124-1, the Company began expensing unrealized losses on available-for-sale securities held in the nuclear decommissioning trusts since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of other-than-temporary impairment. Approximately $0.3 million of unrealized losses on available-for-sale securities were reclassified from OCI to earnings upon adoption of this pronouncement. The balance was determined using the specific identification method. The following table provides the approximate fair value and related carrying amounts of investments other than cash and cash equivalents as of December 31:

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	2006				2005
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Debt securities:
-Government obligations	$	61	$	61	$	59	$	59

The following table summarizes the amortized cost basis, gross unrealized gains and losses and fair values for decommissioning trust investments as of December 31:

	2006								2005
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
Basis				Gains		Losses		Value		Basis		Gains		Losses		Value
(In millions)
Debt securities	$	61	$	-	$	-	$	61	$	60	$	-	$	1	$	59

Unrealized gains applicable to the Company's decommissioning trusts are recognized in OCI in accordance with SFAS 115, as fluctuations in the fair value of these trust balances will eventually affect earnings.

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

	2006		2005		2004
(In millions)
Proceeds from sales	$	53	$	366	$	269
Gross realized gains		-		35		22
Gross realized losses		1		15		13
Interest and dividend income		-		9		9

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

5.     LEASES:

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

The Company and CEI sold their ownership interests in Bruce Mansfield Units 1, 2 and 3 and the Company 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 CEI entered into operating leases for lease terms of approximately 30 years as co-lessees. Subsequent to the intra-system generation assets transfers in the fourth quarter of 2005, the Company and CEI continue to be responsible, to the extent of their leasehold interests during the terms of the leases, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. The Company and CEI have the right, at the end of the respective basic lease terms, to renew the leases. The Company and CEI 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 CEI, the Company is also obligated for CEI's lease payments. If CEI is unable to make its payments under the Bruce Mansfield Plant lease, the Company would be obligated to make such payments. No such payments have been made on behalf of CEI. (CEI's future minimum lease payments as of December 31, 2006 were approximately $0.1 billion, net of trust cash receipts.)

Consistent with the regulatory treatment, the rentals for 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:

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	2006		2005		2004
	(In millions)
Operating leases
Interest element	$	41.1	$	43.9	$	46.4
Other		68.3		62.3		52.9
Total rentals	$	109.4	$	106.2	$	99.3

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

	Operating Leases
	Lease		Capital
	Payments		Trust		Net
	(In millions)
2007	$	101.4	$	22.6	$	78.8
2008		99.3		27.2		72.1
2009		100.5		23.3		77.2
2010		100.8		28.5		72.3
2011		98.8		29.1		69.7
Years thereafter		530.8		120.1		410.7
Total minimum lease payments	$	1,031.6	$	250.8	$	780.8

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 $111 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 $6 million per year). The total above-market lease obligation of $298 million associated with the Bruce Mansfield Plant is being amortized on a straight-line basis through the end of 2016 (approximately $19 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 $243 million, of which $25 million is payable within one year.

The Company and CEI 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 (Offering), the two companies pledged $720 million aggregate principal amount ($145 million for the Company and $575 million for CEI) 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 ($337 million for the Company and $570 million for CEI) 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 obligations 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 (see Note 6 for FIN 46R discussion).

 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.

Shippingport was established to purchase all of the lease obligation bonds issued in connection with the Company's and CEI's Bruce Mansfield Plant sale and leaseback transaction in 1987. The Company and CEI used debt and available funds to purchase the notes issued by Shippingport. Adoption of FIN 46R resulted in the consolidation of Shippingport by CEI as of December 31, 2003.

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 concluded that it was not the primary beneficiary of the owner trusts and it was therefore not required to consolidate these entities. The leases are accounted for as operating leases in accordance with GAAP.

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The Company is exposed to losses under the applicable sale and leaseback agreements upon the occurrence of certain contingent events that the Company considers unlikely to occur. The Company has a maximum exposure to loss under these provisions of approximately $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 agreements, the Company has net minimum discounted lease payments of $503 million, that would not be payable if the casualty value payments are made.  

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 $18 million, which was partially offset by the initial phase-out of the Ohio income-based franchise tax, which reduced income taxes by approximately $1 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.

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The NERC has been preparing the implementation aspects of reorganizing its structure to meet the FERC's certification requirements for the ERO. The NERC 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.

  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. FirstEnergy, 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.

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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 base distribution rates through December 31, 2008 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, 2008 for the Company;

Reducing the deferred shopping incentive balances as of January 1, 2006 by up to $45 million for the Company by accelerating the application of the Company's accumulated cost of removal regulatory liability; and

Recovering increased fuel costs (compared to a 2002 baseline) of up to $75 million, $77 million, and $79 million, in 2006, 2007, and 2008, respectively, from all of OE's and the Company's distribution and transmission customers through a fuel recovery mechanism. The Company may defer and capitalize (for recovery over a 25-year period) increased fuel costs above the amount collected through the 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.

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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.

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.

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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.

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 five million authorized and unissued shares of $25 par value preference stock.

(C)      LONG-TERM DEBT-

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. There also exist cross-default provisions among financing arrangements of FirstEnergy and the Company. Sinking fund requirements for maturing long-term debt for the next five years are $30 million in 2007.

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 $49 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 0.35% of the amount of the policy to the insurer. The Company is obligated to reimburse the insurer for any drawings thereunder.

Certain secured notes of the Company are entitled to the benefit of noncancelable municipal bond insurance policies of $30 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 CEI have unsecured LOCs of approximately $194 million in connection with the sale and leaseback of Beaver Valley Unit 2. The Company and CEI are jointly and severally liable for the LOCs (see Note 5).

10. ASSET RETIREMENT OBLIGATIONS:

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.

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 sale and leaseback arrangements remain with the Company.

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In 2005, the Company revised the ARO associated with Beaver Valley Unit 2, Davis-Besse and Perry as a result of an updated decommissioning study. The present value of revisions in the estimated cash flows associated with projected decommissioning costs connected with the assets subject to sale and leaseback arrangements decreased the ARO and corresponding plant asset for Beaver Valley Unit 2 by $4 million.

The Company continues to maintain the nuclear decommissioning trust funds associated with the sale and leaseback arrangements that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of December 31, 2006, the fair value of the decommissioning trust assets was $61 million.

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

ARO Reconciliation	2006		2005
	(In millions)
Balance at beginning of year	$	25	$	194
Transfers to FGCO and NCG		-		(157	)
Accretion		2		13
Revisions in estimated cash flows		-		(26	)
FIN 47 ARO upon adoption		-		1
Balance at end of year	$	27	$	25

11. SHORT-TERM BORROWINGS:

Short-term borrowings outstanding as of December 31, 2006, consisted of $154 million of borrowings from affiliates. The Company and CEI sell substantially all of their retail customer receivables to CFC, a wholly owned subsidiary of CEI. 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 of December 31, 2006, the facility was undrawn.

On August 24, 2006,the Company, FirstEnergy, OE, Penn, CEI, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, 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. The Company's borrowing limit under the facility is $250 million subject to applicable regulatory approval. The average interest rate on short-term borrowings outstanding as of December 31, 2006 and 2005 was 5.4% and 4.0%, respectively.

12. COMMITMENTS AND CONTINGENCIES:

(A) NUCLEAR INSURANCE-

The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $10.8 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. Based on its leasehold interest in Beaver Valley Unit 2, the Company's maximum potential assessment under the industry retrospective rating plan (assuming the other affiliate co-owners contribute their proportionate shares of any assessments under the retrospective rating plan) would be $18.4 million per incident but not more than $2.8 million in any one year for each incident.

The Company is also insured as to its respective interest in Beaver Valley Unit 2 under policies issued to the operating company of the plant. Under these policies, up to $2.75 billion is provided for property damage and decontamination and decommissioning costs. The Company has also obtained approximately $89.5 million of insurance coverage for replacement power costs for its respective leasehold interest in Beaver Valley Unit 2. Under these policies, the Company can be assessed a maximum of approximately $2.8 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses.

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

(B)    ENVIRONMENTAL MATTERS-

The Company accrues environmental liabilities only when they conclude that it is probable that they have an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in the Company's determination of environmental liabilities and are accrued in the period that they 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 $2.7 million have been accrued through December 31, 2006.

(C) OTHER LEGAL PROCEEDINGS-

Power Outages and Related Litigation

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force's final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy's Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy's 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. 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:

In 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 Company 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 $22.9 million) between the purchase price specified in the Master Facility Lease and the net book value at the date of transfer was credited to equity. FGCO also assumed certain assets and liabilities relating to the purchased units. As consideration, FGCO delivered to the Company a promissory note of approximately $101.0 million that is secured by a lien on the units purchased, bears interest at a rate per annum based on the weighted cost of TE's long-term debt (4.38%) 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 TE'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 $22.1 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 TE's interest in associated decommissioning trust funds, other related assets and other liabilities associated with the transferred assets. In addition, TE received a promissory note from NGC in the principal amount of approximately $726.1 million, 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 TE's weighted average cost of long-term debt (4.38%), 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 a purchase price adjustment of $130.8 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 undertaken 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 or sale to a separate corporate entity. The transactions essentially completed the divestitures of owned assets 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 to 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 the generated KWH sales arrangement and the portion of expenses related to its retained leasehold interests in the Bruce Mansfield Plant and Beaver Valley Unit 2. 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	$	651
Other property and investments		287
Current assets		43
Deferred charges		2
	$	983
Liabilities Related to Assets Transferred
Long-term debt	$	-
Current liabilities		-
Noncurrent liabilities		178
	$	178
Net Assets Transferred	$	805

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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.

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	$	218.0	$	225.6	$	262.8	$	221.6
Expenses		174.8		176.3		219.1		207.3
Operating Income		43.2		49.3		43.7		14.3
Other Income (Expense)		3.0		3.0		3.1		(0.4	)
Income Before Income Taxes		46.2		52.3		46.8		13.9
Income Taxes		17.2		19.9		17.7		5.1
Net Income	$	29.0	$	32.4	$	29.1	$	8.8
Earnings on Common Stock	$	27.8	$	31.2	$	28.0	$	3.0

Three Months Ended	March 31, 2005			June 30, 2005		September 30, 2005		December 31, 2005
	(In millions)
Revenues	$	241.8		$	259.1	$	286.9	$	252.4
Expenses		240.6			224.1		230.2		213.1
Operating Income		1.2			35.0		56.7		39.3
Other Income (Expense)		(1.9	)		2.3		13.9		3.5
Income (Loss) Before Income Taxes		(0.7	)		37.3		70.6		42.8
Income Taxes (Benefit)		(1.1	)		29.6		28.4		16.9
Net Income	$	0.4		$	7.7	$	42.2	$	25.9
Earnings (Loss) on Common Stock	$	(1.8	)	$	5.5	$	40.5	$	24.2

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