OHIO EDISON COMPANY

2006 ANNUAL REPORT TO STOCKHOLDERS

Ohio Edison Company is a wholly owned electric utility operating subsidiary of FirstEnergy Corp. Ohio Edison engages in the distribution and sale of electric energy to communities in an area of 7,000 square miles in central and northeastern Ohio and, through its wholly owned Pennsylvania Power Company subsidiary, 1,100 square miles in western Pennsylvania. The areas Ohio Edison and Pennsylvania Power serve have populations of approximately 2.8 million and 0.3 million, respectively.

Contents	Page
Glossary of Terms	i-ii
Report of Independent Registered Public Accounting Firm	1
Selected Financial Data	2
Management's Discussion and Analysis	3-20
Consolidated Statements of Income	21
Consolidated Balance Sheets	22
Consolidated Statements of Capitalization	23-24
Consolidated Statements of Common Stockholder's Equity	25
Consolidated Statements of Preferred Stock	25
Consolidated Statements of Cash Flows	26
Consolidated Statements of Taxes	27
Notes to Consolidated Financial Statements	28-49

GLOSSARY OF TERMS

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

ATSI	American Transmission Systems, Inc., owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an affiliated Ohio electric utility
Companies	OE and Penn
FENOC	FirstEnergy Nuclear Operating Company, operates nuclear generating facilities
FES	FirstEnergy Solutions Corp., provides energy-related products and services
FESC	FirstEnergy Service Company, provides legal, financial, and other corporate support services
FGCO	FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities
FirstEnergy	FirstEnergy Corp., a public utility holding company
JCP&L	Jersey Central Power & Light Company, an affiliated New Jersey electric utility
Met-Ed	Metropolitan Edison Company, an affiliated Pennsylvania electric utility
NGC	FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities
OE	Ohio Edison Company
Ohio Companies	CEI, OE and TE
Penelec	Pennsylvania Electric Company, an affiliated Pennsylvania electric utility
Penn	Pennsylvania Power Company, OE?s wholly owned Pennsylvania electric utility subsidiary
TE	The Toledo Edison Company, an affiliated Ohio electric utility
The following abbreviations and acronyms are used to identify frequently used terms in this report:
AOCI	Accumulated Other Comprehensive Income
AOCL	Accumulated Other Comprehensive Loss
ARO	Asset Retirement Obligation
B&W	Babcock & Wilcox Company
Bechtel	Bechtel Power Corporation
CAT	Commercial Activity Tax
CBP	Competitive Bid Process
DOJ	United States Department of Justice
ECAR	East Central Area Reliability Coordination Agreement
EPA	U. S. Environmental Protection Agency
EPACT	Energy Policy Act of 2005
ERO	Electric Reliability Organization
ESOP	Employee Stock Ownership Plan
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 and SFAS 124-1	FASB Staff Position No. 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
MW	Megawatts
NERC	North American Electric Reliability Corporation
NOx	Nitrogen Oxide
NOPR	Notice of Proposed Rulemaking
NOV	Notice of Violation
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

i

GLOSSARY OF TERMS, Cont'd.

PPUC	Pennsylvania Public Utility Commission
PSA	Power Supply Agreements
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act of 1935
RCP	Rate Certainty Plan
RSP	Rate Stabilization Plan
RTC	Regulatory Transition Charge
S&P	Standard & Poor's Ratings Service
SCR	Selective Catalytic Reduction
SEC	United States Securities and Exchange Commission
SFAC	Statement of Financial Accounting Concepts
SFAC 7	SFAC No.. 7, "Using Cash Flow Information and Present Value in Accounting Measurements"
SFAS	Statement of Financial Accounting Standards
SFAS 71	SFAS No.. 71, "Accounting for the Effects of Certain Types of Regulation"
SFAS 87	SFAS No.. 87, "Employers' Accounting for Pensions"
SFAS 101	SFAS No.. 101, ?Accounting for Discontinuation of Application of SFAS 71?
SFAS 106	SFAS No.. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions"
SFAS 107	SFAS No.. 107, ?Disclosures about Fair Value of Financial Instruments?
SFAS 115	SFAS No.. 115, "Accounting for Certain Investments in Debt and Equity Securities"
SFAS 143	SFAS No.. 143, "Accounting for Asset Retirement Obligations"
SFAS 144	SFAS No.. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"
SFAS 157	SFAS No.. 157, ?Fair Value Measurements?
SFAS 158	SFAS No.. 158, ?Employers? Accounting for Defined Benefit Pension and Other Postretirement    Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R)?
SFAS 159	SFAS No.. 159, ?The Fair Value Option for Financial Assets and Financial Liabilities - Including an    amendment of FASB Statements No. 115?
SO2	Sulfur Dioxide
VIE(2)	Variable Interest Entity

ii

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Ohio Edison Company:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder?s equity, preferred stock and cash flows present fairly, in all material respects, the financial position of Ohio Edison Company and its subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company?s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

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

As discussed in Note 3 to the consolidated financial statements, the Company changed the manner in which it accounts for defined benefit pension and other postretirement benefit plans as of December 31, 2006. As discussed in Note 2(G) and Note 11 to the consolidated financial statements, the Company changed its method of accounting for conditional asset retirement obligations as of December 31, 2005.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 27, 2007

1

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

OHIO EDISON COMPANY
SELECTED FINANCIAL DATA
For the Years Ended December 31,	2006			2005			2004			2003			2002
	(Dollars in thousands)
GENERAL FINANCIAL INFORMATION:
Operating Revenues	$	2,427,456		$	2,975,553		$	2,945,583		$	2,925,310		$	2,948,675
Operating Income	$	291,132		$	632,543		$	592,643		$	336,936		$	453,831
Income Before Cumulative Effect
of Accounting Changes	$	211,639		$	330,398		$	342,766		$	292,925		$	356,159
Net Income	$	211,639		$	314,055		$	342,766		$	324,645		$	356,159
Earnings on Common Stock	$	207,087		$	311,420		$	340,264		$	321,913		$	349,649
Total Assets	$	5,120,614		$	6,097,277		$	6,482,627		$	7,316,489		$	7,789,539
CAPITALIZATION AS OF DECEMBER 31:
Common Stockholder?s Equity	$	1,972,385		$	2,502,191		$	2,493,809		$	2,582,970		$	2,839,255
Preferred Stock-
Not Subject to Mandatory Redemption		-			75,070			100,070			100,070			100,070
Subject to Mandatory Redemption		-			-			-			-			13,500
Long-Term Debt and Other Long-Term Obligations		1,118,576			1,019,642			1,114,914			1,179,789			1,219,347
Total Capitalization	$	3,090,961		$	3,596,903		$	3,708,793		$	3,862,829		$	4,172,172
CAPITALIZATION RATIOS:
Common Stockholder?s Equity		63.8	%		69.6	%		67.2	%		66.9	%		68.1	%
Preferred Stock-
Not Subject to Mandatory Redemption		-			2.1			2.7			2.6			2.4
Subject to Mandatory Redemption		-			-			-			-			0.3
Long-Term Debt and Other Long-Term Obligations		36.2			28.3			30.1			30.5			29.2
Total Capitalization		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%
DISTRIBUTION KWH DELIVERIES (Millions):
Residential		10,500			10,901			10,180			10,009			10,233
Commercial		8,429			8,566			8,276			8,105			7,994
Industrial		11,018			11,058			10,700			10,658			10,672
Other		152			154			144			160			154
Total		30,099			30,679			29,300			28,932			29,053
CUSTOMERS SERVED:
Residential		1,066,582			1,062,665			1,056,560			1,044,419			1,041,825
Commercial		131,188			130,472			129,017			127,856			119,771
Industrial		1,142			1,152			1,149			1,182			4,500
Other		1,937			1,890			1,751			1,752			1,756
Total		1,200,849			1,196,179			1,188,477			1,175,209			1,167,852
Number of Employees		1,432			1,422			1,370			1,521			1,569

2

OHIO EDISON COMPANY

MANAGEMENT?S DISCUSSION AND

ANALYSIS OF RESULTS OF OPERATIONS

AND FINANCIAL CONDITION

Forward-Looking Statements: This discussion includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms ?anticipate,? ?potential,? ?expect,? ?believe,? ?estimate? and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, the continued ability 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 needed to, among other things, implement the Air Quality Compliance Plan (including that such amounts could be higher than anticipated) or levels of emission reductions related to the Consent Decree resolving the New Source Review litigation, adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or operating permits, fines or other enforcement actions and remedies) of governmental investigations and oversight, including by the Securities and Exchange Commission, the Nuclear Regulatory Commission and the various state public utility commissions as disclosed in our Securities and Exchange Commission filings, generally, and heightened scrutiny at the Perry Nuclear Power Plant in particular, 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 an asset spin-off in the form of a dividend. FENOC continues to operate and maintain the nuclear generation assets.

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

3

The transfers 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 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 Perry Plant and Beaver Valley Unit 2, we have continued the nuclear-generated KWH sales arrangement with FES for the associated output 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	)	$	(146	)
Nuclear-generated KWH sales	(b	)		(290	)
Total - Revenues Effect				(436	)
Expenses:
Fuel costs - nuclear	(c	)		(44	)
Nuclear operating costs	(c	)		(150	)
Provision for depreciation	(d	)		(46	)
General taxes	(e	)		(13	)
Total - Expenses Effect				(253	)
Operating Income Effect				(183	)
Other Income (expense):
Interest income from notes receivable	(f	)		57
Nuclear decommissioning trust earnings	(g	)		(12	)
Interest expense	(h	)		( 7	)
Capitalized interest	(i	)		(9	)
Total - Other Income Effect				43
Income Before Income Taxes Effect				(140	)
Income Taxes	(j	)		(57	)
Net Income Effect			$	(83	)
(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) Elimination of interest on pollution control notes redeemed in conjunction with the       nuclear asset transfer.
(i)  Reduction of allowance for borrowed funds used during construction on nuclear       capital expenditures.
(j)  Income tax effect of the above adjustments.

Results of Operations

Earnings on common stock in 2006 decreased to $207 million from $311 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 decreased $21 million primarily due to lower revenues and increased purchased power costs, partially offset by decreased amortization of regulatory assets.

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

4

Revenues

Revenues decreased by $548 million or 18.4% in 2006 compared with 2005 primarily due to the generation asset transfer impact summarized in the table above. Excluding the effects of the asset transfer, revenues decreased $112 million, primarily due to decreases in wholesale revenues of $247 million and distribution revenues of $449 million, partially offset by an increase in retail generation revenues of $500 million and reduced customer shopping incentives of $82 million.

Revenues increased by $30 million or 1.0% in 2005 compared with 2004 primarily due to increases in retail generation revenues of $50 million and distribution revenues of $43 million, partially offset by decreases of $37 million in wholesale revenues and $32 million in lease revenues from associated companies.

The lower wholesale revenues in 2006 primarily resulted from the termination of a non-affiliated wholesale sales agreement ($203 million) and the December 2005 cessation of the MSG sales arrangements under our transition plan ($56 million). We had been required to provide the MSG to non-affiliated alternative suppliers.

Lower wholesale revenues in 2005 compared to 2004 reflected decreased sales to FES of $61 million, due to reduced nuclear generation available for sale, partially offset by a $24 million increase in sales to non-affiliated customers (including MSG sales) reflecting increased KWH sales (2.7%) and higher unit prices. Revenues from the lease of fossil generation assets to FGCO decreased due to the termination of our lease arrangement in conjunction with the non-nuclear generation asset transfers completed on October 24, 2005.

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

Changes in Generation KWH Sales	2006			2005
Increase (Decrease)
Electric Generation:
Retail		12.4	%		4.4	%
Wholesale*		(64.7	)%		(5.2	)%
Net Decrease in Generation Sales		(7.6	)%		(0.2	)%

Changes in Generation Revenues	2006				2005
Increase (Decrease)	(In millions)
Retail Generation:
Residential		$	188			$20
Commercial			153			9
Industrial			159			21
Total Retail Generation			500			50
Wholesale*			(247	)		(37)
Net Increase in Generation Revenues		$	253			$13
* The 2006 amount excludes impact of generation asset transfers related to nuclear-generated KWH sales.

Increased retail generation revenues for 2006 (as shown in the table above) resulted from higher KWH sales and higher unit prices. The increase in generation KWH sales primarily resulted from decreased customer shopping, as the percentage of generation services provided by alternative suppliers to total sales delivered in our service area decreased by: residential - 10.0 percentage points; commercial - 11.9 percentage points; and industrial - 10.2 percentage points. The decrease in shopping resulted from certain alternative energy suppliers terminating their supply arrangements with our shopping customers in the fourth quarter of 2005. Higher unit prices for generation reflected the rate stabilization charge and the fuel recovery rider, both of which became effective in the first quarter of 2006 under provisions of the RSP and RCP.

Increased retail generation revenues for 2005 (as shown in the table above) reflected the impact of higher KWH sales. The increased generation KWH sales to residential (7.0%) and commercial (4.5%) customers reflected increased air-conditioning loads due to warmer summer weather in 2005, compared to 2004. Increased industrial revenues were primarily due to higher unit prices and an increase in generation KWH sales of 1.9%. Industrial sales were also impacted by increased shopping as generation services provided to industrial customers by alternative suppliers as a percent of total industrial sales delivered in our service area increased by 1.0 percentage point compared to 2004. Commercial customer shopping decreased slightly and residential customer shopping remained relatively unchanged from 2004.

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		(3.7	)%		7.1	%
Commercial		(1.6	)%		3.5	%
Industrial		(0.4	)%		3.3	%
Net Change in Distribution Deliveries		(1.9	)%		4.7	%

Changes in Distribution Revenues	2006				2005
Increase (Decrease)	(In millions)
Residential		$	(195	)	$	44
Commercial			(136	)		2
Industrial			(118	)		(3	)
Net Change in Distribution Revenues		$	(449	)	$	43

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

Distribution revenues increased in 2005 compared with 2004 due to higher distribution deliveries to residential and commercial customers due to warmer summer weather in 2005, partially offset by lower unit prices. Revenues in the industrial sector decreased due to lower unit prices, offsetting an increase due to higher distribution deliveries.

Expenses

  Total expenses decreased by $207 million in 2006 and by $10 million in 2005. The change in 2006 was impacted by the effects of the generation asset transfers shown in the table above. Excluding the asset transfer effects in 2006, the following table presents changes from the prior year by expense category:

Expenses - Changes	2006			2005
Increase (Decrease)	(In millions)
Fuel costs	$	1		$	(3	)
Purchased power costs		337			(31	)
Nuclear operating costs		(1	)		(38	)
Other operating costs		(26	)		68
Provision for depreciation		11			(14	)
Amortization of regulatory assets		(267	)		46
Deferral of new regulatory assets		(9	)		(51	)
General taxes		-			13
Net change in expenses	$	46		$	(10	)

 Increased purchased power costs in 2006 reflected higher unit prices associated with our current power supply agreement with FES (see Outlook - Regulatory Matters), partially offset by a decrease in KWH purchased to meet sales requirements. The decrease in other operating costs during 2006 was primarily due to lower transmission expenses as a result of alternative energy suppliers terminating their supply arrangements with our shopping customers in the fourth quarter of 2005 and lower employee benefit expenses. These decreases in 2006 were partially offset by increases in transmission expenses related to MISO Day 2 operations that began on April 1, 2005.

   Excluding the effects of the generation asset transfers, depreciation expense was higher in 2006 primarily as a result of the termination of the PUCO-approved depreciation reserve adjustment program at the end of 2005. The decrease in depreciation expense in 2005 compared to 2004 was attributable to revised estimated service life assumptions for fossil generating plants and a decrease in the depreciation of leased electric plant due to the generation asset transfer.

6

Lower amortization of regulatory assets in 2006 was due to the completion of the generation-related transition cost amortization under our transition plans, partially offset by the amortization of deferred MISO costs for which recovery began in 2006. The increased deferrals of new regulatory assets in 2006 resulted primarily from the deferral of fuel costs ($58 million) and distribution costs ($74 million) under the RCP, partially offset by lower MISO cost deferrals ($43 million) and the decrease in shopping incentive deferrals ($84 million) which ceased in 2006 under the Ohio transition plan. The deferral of interest on the unamortized shopping incentive balances continues under the RCP (see Outlook - Regulatory Matters).

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

Increases in amortization of regulatory assets in 2005 compared to 2004 resulted from higher amortization of Ohio transition regulatory assets, partially offset by increased cost deferrals of new regulatory assets. The higher deferrals in 2005 compared to 2004 primarily resulted from the PUCO-approved MISO cost deferrals and related interest ($49 million).

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

Other Income

Other income increased $36 million in 2006 compared to 2005, reflecting the effects of the generation asset transfers in the table above. Excluding the effects of the generation asset transfers, other income decreased by $7 million in 2006 primarily due to an increase in interest expense resulting from our June 2006 issuance of $600 million of long-term debt and costs related to our fourth quarter 2006 pollution control note redemptions. These items were partially offset by the absence of the 2005 civil penalty and environmental liability discussed below.

Other income decreased by $21 million in 2005 compared to 2004 due to an $8.5 million civil penalty paid to the DOJ and a $10 million liability for environmental projects recognized in connection with the W. H. Sammis Plant settlement (see Outlook - Environmental Matters), partially offset by higher interest income earned on associated company notes receivable. Interest on long-term debt was lower due to the redemption of $124 million of pollution control notes in 2005. We also optionally redeemed $38 million of Penn?s preferred stock in 2005.

Income Taxes

Income taxes decreased $186 million in 2006 compared to 2005. Excluding the effects of the generation asset transfer, income taxes decreased $129 million primarily due to lower taxable income and the absence in 2006 of approximately $32 million of income tax charges from the implementation of Ohio tax legislation changes in the second quarter of 2005.

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

7

Cumulative Effect of a Change in Accounting Principle

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

Preferred Stock Dividend Requirements and Redemption Premium

Preferred stock dividend requirements and redemption premium increased by $2 million in 2006 from 2005 principally due to costs associated with optional preferred stock redemptions of $75 million in 2006. As of December 31, 2006, all formerly outstanding preferred stock had been redeemed.

Capital Resources and Liquidity

Our cash requirements in 2006 for operating expenses, construction expenditures, scheduled debt maturities and optional preferred stock redemptions were met with a combination of cash from operations, short-term credit arrangements and funds from the capital markets. 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.

Changes in Cash Position

As of December 31, 2006, our cash and cash equivalents of approximately $1 million remained unchanged from December 31, 2005.

Cash Flows From Operating Activities

                    Net cash provided from operating activities was $307 million in 2006, $915 million in 2005 and $416 million in 2004, summarized as follows:

Operating Cash Flows	2006			2005			2004
	(In millions)
Net income	$	212		$	314		$	343
Net-cash charges (credits)		(2	)		441			433
Pension trust contribution*		6			(73	)		(44	)
Working capital and other		91			233			(316	)
Net cash provided from operating activities	$	307		$	915		$	416

* Pension trust contributions in 2005 and 2004 are net of $34 million and $29 million of related

current year cash income tax benefits, respectively. The $6 million cash inflow in 2006 represents

income tax benefits in 2006 relating to a January 2007 pension contribution.

Net cash provided from operating activities decreased $608 million in 2006 compared to 2005 primarily due to a $102 million decrease in net income and a $443 million decrease in non-cash charges as described above under ?Results of Operations? and a $142 million decrease from changes in working capital and other, partially offset by a $79 million increase in after-tax pension trust contributions. The decrease in working capital and other primarily reflects the absence in 2006 of $136 million in funds received under the Energy for Education program in 2005 and changes in accounts payable of $99 million, partially offset by changes in accrued taxes of $41 million (net of taxes on pension trust contributions) and changes in accounts receivables of $19 million and accrued interest of $20 million.

8

Net cash provided from operating activities increased $499 million in 2005 compared to 2004 primarily due to a $549 million increase from changes in working capital and other and an $8 million increase in non-cash charges, partially offset by a $29 million decrease in net income (see ?Results of Operations?) and a $29 million decrease in after-tax pension trust contributions. The increase in working capital and other primarily reflects decreased outflows of $417 million from reduced tax payments, changes in accounts payable of $126 million and $136 million of funds received in 2005 for prepaid electric service (under a three-year Energy for Education Program with the Ohio Schools Council), partially offset by a $124 million decrease in cash provided from the settlement of receivables.

Cash Flows From Financing Activities

In 2006, 2005 and 2004, net cash used for financing activities of $935 million, $728 million and $569 million, respectively, primarily reflected the securities issues and redemptions shown below:

Securities Issued or Redeemed	2006			2005		2004
	(In millions)
New Issues:
Pollution control notes	$	-		$	146	$	30
Unsecured notes		592			-		-
	$	592		$	146	$	30
Redemptions:
Common Stock	$	500		$	-	$	-
FMB		1			81		63
Pollution control notes		606			271		-
Secured notes		5			56		62
Preferred stock		78			38		1
Long-term revolving credit		-			-		40
Other		1			6		6
	$	1,191		$	452	$	172
Short-term borrowings (repayments), net	$	(187	)	$	26	$	(4	)

Net cash used for financing activities increased to $935 million in 2006 from $728 million in 2005. The increase resulted from a $500 million repurchase of common stock and a net increase of $6 million in debt refinancings as shown above, partially offset by a $298 million decrease in common stock dividends to FirstEnergy. Net cash used for financing activities increased to $728 million in 2005 from $569 million in 2004. The increase resulted from a net increase of $134 million in debt refinancings as shown above and a $25 million increase in common stock dividends paid to FirstEnergy.

We had approximately $459 million of cash and temporary cash investments (which include short-term notes receivable from associated companies) and $117 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, which is available through the bank facility and the utility money pool described below. Penn has authorization from the FERC to incur short-term debt up to its charter limit of $39 million as of December 31, 2006, and also has access to the bank facility and the utility money pool.

 OES Capital, our wholly owned subsidiary, has borrowings that are secured by customer accounts receivable purchased from us. OES Capital can borrow up to $170 million under a receivables financing arrangement. As a separate legal entity with separate creditors, OES Capital would have to satisfy its obligations to creditors before any of its remaining assets could be made available to us. As of December 31, 2006, the facility was undrawn.

Penn Power Funding LLC (Penn Funding), a wholly owned subsidiary of Penn, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Penn. Penn Funding can borrow up to $25 million under a receivables financing arrangement which expires June 28, 2007. As a separate legal entity with separate creditors, Penn Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Penn. As of December 31, 2006, the facility was undrawn.

As of December 31, 2006, we had the aggregate capability to issue approximately $1.4 billion of additional FMB on the basis of property additions and retired bonds under the terms of our mortgage indentures. Our issuance of FMB is also subject to provisions of our senior note 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, we are permitted under the indenture to incur additional secured debt not otherwise permitted by a specified exception of up to $543 million as of December 31, 2006. As a result of our redeeming all remaining outstanding preferred stock during 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.

9

 As of December 31, 2006, we had approximately $400 million of capacity remaining unused under our existing shelf registration for unsecured debt securities.

 On August 24, 2006, we, FirstEnergy, CEI, TE, 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 $500 million and Penn?s is $50 million, subject in each case to applicable regulatory approvals.

 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. Total unused borrowing capability under the credit facility and accounts receivable financing facilities was $745 million as of December 31, 2006.

 The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of December 31, 2006, debt to total capitalization as defined under the revolving credit facility was 41% for OE and 24% for Penn.

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 credit ratings. Pricing is defined in ?pricing grids?, whereby the cost of funds borrowed under the facility is related to our credit ratings.

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

Our access to the capital markets and the costs of financing are influenced by the ratings of its securities. The ratings outlook from S&P and Fitch on all securities is stable. The ratings outlook from Moody's on all securities is positive.

Ratings of Securities	Securities	S&P	Moody?s	Fitch
FirstEnergy	Senior unsecured	BBB-	Baa3	BBB
OE	Senior unsecured	BBB-	Baa2	BBB
Penn	Senior secured	BBB+	Baa1	BBB+

On June 26, 2006, OE issued $600 million of unsecured senior notes, comprised of $250 million of 6.4% notes due 2016 and $350 million of 6.875% notes due 2036. The net proceeds from these offerings were used in July 2006 to repurchase $500 million of OE common stock from FirstEnergy, redeem approximately $61 million of our preferred stock and to reduce short-term borrowings.

In April and December of 2006, pollution control notes totaling $552 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 $279 million of pollution control notes remain subject to transfer.

Cash Flows From Investing Activities

Net cash provided from investing activities was $628 million in 2006 compared to $188 million used for investing activities in 2005. The $816 million change resulted primarily from a $354 million increase in payments received on long-term notes receivable from associated companies, a $114 million increase in short-term loan repayments from associated companies, a $162 million change in cash investments and a $144 million decrease in property additions due to the generation asset transfers.

10

Net cash used for investing activities totaled $188 million in 2005 compared to $152 million provided from investing activities in 2004. The $340 million change resulted primarily from the absence in 2005 of $278 million of cash proceeds from certificates of deposit in 2004, loan repayments made to associated companies and $78 million of investments for an escrow fund and a mortgage indenture deposit, partially offset by a $193 million increase in payments received on long-term notes receivable from associated companies.

Our capital spending for the period 2007-2011 is expected to be about $776 million, of which approximately $146 million applies to 2007. The capital spending is primarily for property additions supporting the distribution of electricity. In addition, there are capital spending requirements related to our interests in generating plants leased from non-affiliates.

Contractual Obligations

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

					2008-		2010-
Contractual Obligations	Total		2007		2009		2011		Thereafter
	(In millions)
Long-term debt (1)	$	1,294	$	4	$	181	$	66	$	1,043
Short-term borrowings		117		117		-		-		-
Interest on long-term debt		1,135		66		121		117		831
Capital leases		1		-		1		-		-
Operating leases (2)		1,071		86		218		210		557
Pension funding (3)		20		20		-		-		-
Purchases (4)		123		3		41		18		61
Total	$	3,761	$	296	$	562	$	411	$	2,492

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

⁽²⁾ Operating lease payments are net of capital trust receipts of $416.3 million (see Note 6).  

⁽³⁾   We estimate that no 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 statemenets.

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

Off-Balance Sheet Arrangements

We have obligations that are not included on our Consolidated Balance Sheets related to the sale and leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2, which are satisfied through operating lease payments (see Note 6). The present value of these operating lease commitments, net of trust investments, was $632 million as of December 31, 2006.

Interest Rate Risk

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

11

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	$	40		$	17		$	25		$	29		$	30		$	1,411		$	1,552		$	1,618
Average interest rate		8.2	%		8.2	%		8.5	%		8.6	%		8.6	%		5.3	%		5.6	%
Liabilities Long-term Debt and Other
Long-Term Obligations:
Fixed rate	$	4		$	179		$	2		$	65		$	1		$	781		$	1,032		$	1,075
Average interest rate		8.2	%		4.1	%		8.0	%		5.5	%		9.7	%		6.5	%		6.0	%
Variable rate																$	262		$	262		$	262
Average interest rate																	3.9	%		3.9	%
Short-term Borrowings	$	117																	$	117		$	117
Average interest rate		4.0	%																	4.0	%

Equity Price Risk

Included in our nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $80 million and $67 million as of December 31, 2006 and 2005, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $8 million reduction in fair value as of December 31, 2006. As discussed in Note 5 - Fair Value of Financial Instruments, our nuclear decommissioning trust investments were transferred to NGC as part of the intra-system generation asset transfers with the exception of an amount related to our retained leasehold interests in nuclear generation assets.

Outlook

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

Regulatory Matters

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

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.

12

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 $75 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 TE?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	$	179
2008		208
Total Amortization	$	387

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.

13

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 two power sales agreements for approval with the FERC. One power sales agreement provided for FES to provide the PLR requirements of the Ohio Companies at a price equal to the retail generation rates approved by the PUCO for a period of three years beginning January 1, 2006. The Ohio Companies will be relieved of their obligation to obtain PLR power requirements from FES if the Ohio CBP results in a lower price for retail customers. A similar power sales agreement between FES and Penn permits Penn to obtain its PLR power requirements from FES at a fixed price equal to the retail generation price during 2006.

On December 29, 2005, the FERC issued an order setting the two power sales agreements 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 agreements. 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 and the Ohio Companies, Penn, 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 both the Ohio and Penn power supply agreements with FES. Under the Ohio 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. In addition, pursuant to the settlement, the wholesale rate charged by FES under the Penn power supply agreement can be no greater than the generation component of charges for retail PLR load in Pennsylvania. The modifications to the Ohio and Pennsylvania power supply agreements became effective January 1, 2006. The Penn supply agreement subject to the settlement expired at midnight on December 31, 2006.

As a result of Penn?s PLR competitive solicitation process approved by the PPUC for the period January 1, 2007 through May 31, 2008, FES was selected as the winning bidder for a number of the tranches for individual customer classes. The balance of the tranches will be supplied by unaffiliated power suppliers. On October 2, 2006, FES filed an application with the FERC under Section 205 of the Federal Power Act for authorization to make these affiliate sales to Penn. Interventions or protests were due on this filing on October 23, 2006. Penn was the only party to file an intervention in this proceeding. This filing was accepted by the FERC on November 15, 2006, and no requests for rehearing were filed.

14

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

Environmental Matters

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

         W. H. Sammis Plant-

In 1999 and 2000, the EPA issued NOV or compliance orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as the New Source Review cases.

On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the New Source Review litigation. This settlement agreement, which is in the form of a consent decree, was approved by the Court on July 11, 2005, and requires reductions of NO_X and SO₂ emissions at the W. H. Sammis Plant and other coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if we fail to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, we could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation are currently estimated to be $1.5 billion ($400 million of which is expected to be spent in 2007, with the largest portion of the remaining $1.1 billion expected to be spent in 2008 and 2009).

The Sammis NSR Litigation consent decree also requires us to spend up to $25 million toward environmentally beneficial projects, $14 million of which is satisfied by entering into 93 MW (or 23 MW if federal tax credits are not applicable) of wind energy purchased power agreements with a 20-year term. An initial 16 MW of the 93 MW consent decree obligation was satisfied during 2006.

On August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of SO₂ emissions. FGCO also entered into an agreement with B&W on August 25, 2006 to supply flue gas desulfurization systems for the reduction of SO₂ emissions. Selective Catalytic Reduction (SCR) systems for the reduction of NOx emissions also are being installed at the W.H. Sammis Plant under a 1999 agreement with B&W.

OE and Penn agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 included the penalties paid by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized liabilities in the first quarter of 2005 of $9.2 million and $0.8 million, respectively, for probable future cash contributions toward environmentally beneficial projects.

15

Other Legal Proceedings

Power Outage and Related Litigation-

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

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

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

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

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

Critical Accounting Policies

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

Regulatory Accounting

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

Revenue Recognition

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

Pension and Other Postretirement Benefits Accounting

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

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

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

As of December 31, 2006, we adopted SFAS 158 which requires a net liability or asset to be recognized for the overfunded or underfunded status of our defined benefit pension and other postretirement benefit plans on the balance sheet and recognize changes in funded status in the year in which the changes occur through other comprehensive income. We will continue to apply the provisions of SFAS 87 and SFAS 106 in measuring plan assets and benefit obligations as of the balance sheet date and in determining the amount of net periodic benefit cost. FirstEnergy?s underfunded status 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. 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 $20 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 OE's portion of pension and OPEB costs from changes in key assumptions are as follows:

Increase in Costs from Adverse Changes in Key Assumptions
Assumption	Adverse Change			Pension		OPEB		Total
				(In millions)
Discount rate		Decrease by 0.25	%	$	1.9	$	0.2	$	2.1
Long-term return on assets		Decrease by 0.25	%	$	2.2	$	-	$	2.2
Health care trend rate		Increase by 1	%		na	$	0.7	$	0.7

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Ohio Transition Cost Amortization

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

Long-Lived Assets

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

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

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.

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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.

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OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2006			2005			2004
	(In thousands)
REVENUES (Note 2(I)):
Electric sales	$            2,312,956			$             2,861,043			$            2,834,538
Excise tax collections	114,500			114,510			111,045
		2,427,456			2,975,553			2,945,583
EXPENSES (Note 2(I)):
Fuel		11,047			53,113			56,560
Purchased power		1,275,975			939,193			970,670
Nuclear operating costs		186,377			337,901			375,309
Other operating costs		378,717			404,763			336,772
Provision for depreciation		72,982			108,583			122,413
Amortization of regulatory assets		190,245			457,205			411,326
Deferral of new regulatory assets		(159,465	)		(151,032	)		(100,633	)
General taxes		180,446			193,284			180,523
Total expenses		2,136,324			2,343,010			2,352,940
OPERATING INCOME		291,132			632,543			592,643
OTHER INCOME (EXPENSE) (Note 2(I)):
Investment income		130,853			99,269			96,030
Miscellaneous expense		1,751			(25,190	)		(765	)
Interest expense		(90,355	)		(75,388	)		(71,491	)
Capitalized interest		2,198			10,849			7,211
Subsidiary's preferred stock dividend requirements		(597	)		(1,689	)		(2,560	)
Total other income		43,850			7,851			28,425
INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		334,982			640,394			621,068
INCOME TAXES		123,343			309,996			278,302
INCOME BEFORE CUMULATIVE EFFECT OF
A CHANGE IN ACCOUNTING PRINCIPLE		211,639			330,398			342,766
Cumulative effect of a change in accounting principle
(net of income tax benefit of $9,223,000) (Note 2(G))		-			(16,343	)		-
NET INCOME		211,639			314,055			342,766
PREFERRED STOCK DIVIDEND REQUIREMENTS
AND REDEMPTION PREMIUM		4,552			2,635			2,502
EARNINGS ON COMMON STOCK	$	207,087		$	311,420		$	340,264
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

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OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31,	2006		2005
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	712		$	929
Receivables-
Customers (less accumulated provisions of $15,033,000 and $7,619,000, respectively,
for uncollectible accounts)		234,781			290,887
Associated companies		141,084			187,072
Other (less accumulated provisions of $1,985,000 and $4,000, respectively,
for uncollectible accounts)		13,496			15,327
Notes receivable from associated companies		458,647			536,629
Prepayments and other		13,606			93,129
		862,326			1,123,973
UTILITY PLANT:
In service		2,632,207			2,526,851
Less - Accumulated provision for depreciation		1,021,918			984,463
		1,610,289			1,542,388
Construction work in progress		42,016			58,785
		1,652,305			1,601,173
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies		1,219,325			1,758,776
Investment in lease obligation bonds (Note 6)		291,393			325,729
Nuclear plant decommissioning trusts		118,209			103,854
Other		38,160			44,210
		1,667,087			2,232,569
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		741,564			774,983
Prepaid pension costs		68,420			224,813
Property taxes		60,080			52,875
Unamortized sale and leaseback costs		50,136			55,139
Other		18,696			31,752
		938,896			1,139,562
	$	5,120,614		$	6,097,277
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	159,852		$	280,255
Short-term borrowings-
Associated companies		113,987			57,715
Other		3,097			143,585
Accounts payable-
Associated companies		115,252			172,511
Other		13,068			9,607
Accrued taxes		187,306			163,870
Accrued interest		24,712			8,333
Other		64,519			61,726
		681,793			897,602
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity		1,972,385			2,502,191
Preferred stock not subject to mandatory redemption		-			60,965
Preferred stock of consolidated subsidiary not subject to mandatory redemption		-			14,105
Long-term debt and other long-term obligations		1,118,576			1,019,642
		3,090,961			3,596,903
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		674,288			769,031
Accumulated deferred investment tax credits		20,532			24,081
Asset retirement obligations		88,223			82,527
Retirement benefits		167,510			291,051
Deferred revenues - electric service programs		86,710			121,693
Other		310,597			314,389
		1,347,860			1,602,772
COMMITMENTS AND CONTINGENCIES (Notes 6 and 13)
	$	5,120,614		$	6,097,277
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.

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OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
	Shares Outstanding				Dollars in Thousands
As of December 31,	2006		2005		2006		2005
COMMON STOCKHOLDER'S EQUITY:
Common stock, without par value, 175,000,000 shares authorized		80		100	$	1,708,441	$	2,297,253
Accumulated other comprehensive income (loss) (Note 2(F))						3,208		4,094
Retained earnings (Note 10(A))						260,736		200,844
Total						1,972,385		2,502,191
PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION (Note 10(B)):
Cumulative, $100 par value, 6,000,000 shares authorized-
3.90%		-		152,510		-		15,251
4.40%		-		176,280		-		17,628
4.44%		-		136,560		-		13,656
4.56%		-		144,300		-		14,430
Total		-		609,650		-		60,965
PREFERRED STOCK OF CONSOLIDATED SUBSIDIARY NOT SUBJECT TO
MANDATORY REDEMPTION (Note 10(B)):
Pennsylvania Power Company-
Cumulative, $100 par value, 1,200,000 shares authorized-
4.24%		-		40,000		-		4,000
4.25%		-		41,049		-		4,105
4.64%		-		60,000		-		6,000
Total		-		141,049		-		14,105
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 10(C)):
Ohio Edison Company-
Secured notes:
* 3.050% due 2015						-		19,000
* 3.250% due 2015						-		50,000
* 3.200% due 2016						-		47,725
7.050% due 2020						-		60,000
5.375% due 2028						13,522		13,522
* 3.780% due 2029						100,000		100,000
* 3.750% due 2029						6,450		6,450
* 3.050% due 2030						-		60,400
* 3.350% due 2031						-		69,500
* 3.100% due 2033						-		12,300
5.450% due 2033						-		14,800
* 3.350% due 2033						-		50,000
* 3.100% due 2033						-		108,000
Limited Partnerships-
7.24% weighted average interest rate due 2006-2010						8,253		12,859
Total						128,225		624,556
* Denotes variable rate issue with applicable year-end interest rate shown.

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OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)
	Dollars in Thousands
As of December 31,	2006			2005
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Cont'd)
Ohio Edison Company-
Unsecured notes:
4..000% due 2008	$	175,000		$	175,000
* 3.900% due 2014		50,000			50,000
5..450% due 2015		150,000			150,000
6..400% due 2016		250,000			-
* 4.020% due 2018		33,000			33,000
* 3.960% due 2018		23,000			23,000
* 3.950% due 2023		50,000			50,000
6..875% due 2036		350,000			-
Total		1,081,000			481,000
Pennsylvania Power Company-
First mortgage bonds:
9..740% due 2007-2019		12,695			13,669
7..625% due 2023		6,500			6,500
Total		19,195			20,169
Secured notes:
5..400% due 2013		1,000			1,000
5..400% due 2017		-			10,600
* 3.300% due 2017		-			17,925
5.900% due 2018		-			16,800
* 3.300% due 2021		-			10,525
6..150% due 2023		-			12,700
* 3.610% due 2027		-			10,300
5..375% due 2028		1,734			1,734
5..450% due 2028		-			6,950
6..000% due 2028		-			14,250
Total		2,734			102,784
Unsecured notes:
* 3.500% due 2029		-			14,500
5..390% due 2010 to associated company		62,900			62,900
Total		62,900			77,400
Capital lease obligations (Note 6)		362			3,312
Net unamortized discount on debt		(15,988	)		(9,324	)
Long-term debt due within one year		(159,852	)		(280,255	)
Total long-term debt and other long-term obligations		1,118,576			1,019,642
TOTAL CAPITALIZATION	$	3,090,961		$	3,596,903
* 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.

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OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
										Accumulated
										Other
	Comprehensive			Number			Carrying			Comprehensive			Retained
	Income			of Shares			Value			Income (Loss)			Earnings
	(Dollars in thousands)
Balance, January 1, 2004					100		$	2,098,729		$	(38,693	)	$	522,934
Net income	$	342,766												342,766
Minimum liability for unfunded retirement
benefits, net of $5,516,000 of income tax benefits		(7,552	)								(7,552	)
Unrealized loss on investments, net of
$533,000 of income tax benefits		(873	)								(873	)
Comprehensive income	$	334,341
Cash dividends on preferred stock														(2,502	)
Cash dividends on common stock														(421,000	)
Balance, December 31, 2004					100			2,098,729			(47,118	)		442,198
Net income	$	314,055												314,055
Minimum liability for unfunded retirement
benefits, net of $49,027,000 of income taxes		69,463									69,463
Unrealized loss on investments, net of
$13,068,000 of income tax benefits		(18,251	)								(18,251	)
Comprehensive income	$	365,267
Affiliated company asset transfers								198,147						(106,774	)
Restricted stock units								32
Preferred stock redemption adjustment								345
Cash dividends on preferred stock														(2,635	)
Cash dividends on common stock														(446,000	)
Balance, December 31, 2005					100			2,297,253			4,094			200,844
Net income	$	211,639												211,639
Unrealized gain on investments, net of
$4,455,000 of income taxes		7,954									7,954
Comprehensive income	$	219,593
Net liability for unfunded retirement benefits
due to the implementation of SFAS 158, net
of $22,287,000 of income tax benefits											(8,840	)
Affiliated company asset transfers (Note 14)								(87,893	)
Restricted stock units								58
Stock based compensation								82
Repurchase of common stock					(20	)		(500,000	)
Preferred stock redemption adjustments								(1,059	)					604
Preferred stock redemption premiums														(2,928	)
Cash dividends on preferred stock														(1,423	)
Cash dividends on common stock														(148,000	)
Balance, December 31, 2006					80		$	1,708,441		$	3,208		$	260,736

CONSOLIDATED STATEMENTS OF PREFERRED STOCK
	Not Subject to						Subject to
	Mandatory Redemption						Mandatory Redemption*
	Number			Par			Number			Par
	of Shares			Value			of Shares			Value
	(Dollars in thousands)
Balance, January 1, 2004		1,000,699		$	100,070			135,000		$	13,500
Redemptions-
7.625% Series								(7,500	)		(750	)
Balance, December 31, 2004		1,000,699			100,070			127,500			12,750
Redemptions-
7.750% Series		(250,000	)		(25,000	)
7.625% Series								(127,500	)		(12,750	)
Balance, December 31, 2005		750,699			75,070			-			-
Redemptions-
3.90% Series		(152,510	)		(15,251	)
4.40% Series		(176,280	)		(17,628	)
4.44% Series		(136,560	)		(13,656	)
4.56% Series		(144,300	)		(14,430	)
4.24% Series		(40,000	)		(4,000	)
4.25% Series		(41,049	)		(4,105	)
4.64% Series		(60,000	)		(6,000	)
Balance, December 31, 2006		-		$	-			-		$	-
* Preferred stock subject to mandatory redemption is classified as debt under SFAS 150.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

25

OHIO 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		$	211,639		$	314,055		$	342,766
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation			72,982			108,583			122,413
Amortization of regulatory assets			190,245			457,205			411,326
Deferral of new regulatory assets			(159,465	)		(151,032	)		(100,633	)
Nuclear fuel and lease amortization			735			45,769			42,811
Amortization of lease costs			(7,928	)		(6,365	)		(5,170	)
Deferred income taxes and investment tax credits, net			(68,259	)		(29,750	)		(44,469	)
Accrued compensation and retirement benefits			5,004			14,506			35,840
Cumulative effect of a change in accounting principle			-			16,343			-
Pension trust contribution			-			(106,760	)		(72,763	)
Decrease (increase) in operating assets-
Receivables			103,925			84,688			209,130
Materials and supplies			-			(3,367	)		(10,259	)
Prepayments and other current assets			1,275			(1,778	)		1,286
Increase (decrease) in operating liabilities-
Accounts payable			(53,798	)		45,149			(80,738	)
Accrued taxes			23,436			10,470			(406,945	)
Accrued interest			16,379			(3,659	)		(6,722	)
Electric service prepayment programs			(34,983	)		121,692			-
Other			5,882			(464	)		(21,519	)
Net cash provided from operating activities			307,069			915,285			416,354
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt			592,180			146,450			30,000
Short-term borrowings, net			-			26,404			-
Redemptions and Repayments-
Common stock			(500,000	)		-			-
Preferred stock			(78,480	)		(37,750	)		(750	)
Long-term debt			(613,002	)		(414,020	)		(170,997	)
Short-term borrowings, net			(186,511	)		-			(4,015	)
Dividend Payments-
Common stock			(148,000	)		(446,000	)		(421,000	)
Preferred stock			(1,423	)		(2,635	)		(2,502	)
Net cash used for financing activities			(935,236	)		(727,551	)		(569,264	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(123,210	)		(266,823	)		(235,022	)
Proceeds from nuclear decommissioning trust fund sales			42,021			428,954			173,976
Investments in nuclear decommissioning trust funds			(44,095	)		(460,494	)		(205,516	)
Loan repayments from (loans to) associated companies, net			78,101			(35,553	)		120,706
Collection of principal on long-term notes receivable			553,734			199,848			7,348
Cash investments			112,584			(49,270	)		28,877
Proceeds from certificates of deposit			-			-			277,763
Other			8,815			(4,697	)		(15,875	)
Net cash provided from (used for) investing activities			627,950			(188,035	)		152,257
Net decrease in cash and cash equivalents			(217	)		(301	)		(653	)
Cash and cash equivalents at beginning of year			929			1,230			1,883
Cash and cash equivalents at end of year		$	712		$	929		$	1,230
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)		$	57,243		$	67,239		$	65,765
Income taxes		$	156,610		$	285,819		$	419,123
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

26

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF TAXES
For the Years Ended December 31,	2006			2005			2004
	(In thousands)
GENERAL TAXES:
Ohio kilowatt-hour excise*	$	95,154		$	94,085		$	91,811
State gross receipts*		19,346			20,425			19,234
Real and personal property		54,908			67,438			58,000
Social security and unemployment		7,419			7,481			7,048
Other		3,619			3,855			4,430
Total general taxes	$	180,446		$	193,284		$	180,523
PROVISION FOR INCOME TAXES:
Currently payable-
Federal	$	161,880		$	274,676		$	246,864
State		29,722			74,293			75,907
		191,602			348,969			322,771
Deferred, net-
Federal		(57,330	)		(60,252	)		(23,668	)
State		(7,241	)		36,798			(5,512	)
		(64,571	)		(23,454	)		(29,180	)
Investment tax credit amortization		(3,688	)		(15,519	)		(15,289	)
Total provision for income taxes	$	123,343		$	309,996		$	278,302
RECONCILIATION OF FEDERAL INCOME TAX
EXPENSE AT STATUTORY RATE TO TOTAL
PROVISION FOR INCOME TAXES:
Book income before provision for income taxes	$	334,982		$	640,394		$	621,068
Federal income tax expense at statutory rate	$	117,244		$	224,138		$	217,374
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits		(3,688	)		(15,519	)		(15,289	)
State income taxes, net of federal income tax benefit		14,613			72,209			45,757
Amortization of tax regulatory assets		3,744			7,341			6,130
Penalties		-			2,975			-
Competitive transition charge		2,685			31,934			27,889
Low income housing and franchise credits		(7,001	)		(6,796	)		(8,615	)
Other, net		(4,254	)		(6,286	)		5,056
Total provision for income taxes	$	123,343		$	309,996		$	278,302
ACCUMULATED DEFERRED INCOME TAXES AS OF
DECEMBER 31:
Property basis differences	$	496,670		$	480,859		$	451,269
Allowance for equity funds used during construction		22,738			25,470			27,730
Regulatory transition charge		(28,341	)		6,653			154,015
Asset retirement obligations		9,928			-			21,253
Customer receivables for future income taxes		31,283			33,946			39,266
Deferred sale and leaseback costs		(54,515	)		(59,225	)		(63,432	)
Unamortized investment tax credits		(8,291	)		(9,605	)		(23,510	)
Deferred gain on asset sales to affiliated companies		46,809			50,304			51,716
Other comprehensive income		(15,143	)		2,689			(33,268	)
Retirement benefits		30,334			30,849			(6,202	)
Deferred customer shopping incentive		68,457			123,029			94,002
Other		74,359			84,062			53,437
Net deferred income tax liability	$	674,288		$	769,031		$	766,276
* 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.

27

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION:

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

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

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

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

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

? are cost-based; and

? can be charged to and collected from customers.

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

Regulatory Assets-

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

28

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

	2006*			2005*
	(In millions)
Regulatory transition costs	$	280		$	369
Customer shopping incentives		174			325
Customer receivables for future income taxes		81			88
Loss on reacquired debt		24			22
Asset removal costs		(3	)		(80	)
MISO transmission costs		44			49
Fuel costs?RCP		57			-
Distribution costs?RCP		74			-
Other		10			2
Total	$	741		$	775

* Penn had net regulatory liabilities of approximately $69 million and $59 million included in Other Noncurrent Liabilities on the Consolidated Balance Sheets as of December 31, 2006 and 2005, respectively.

The Company had been deferring customer shopping incentives and interest costs (Extended RTC) as new regulatory assets in accordance with its prior transition and rate stabilization plans. As a result of the RCP approved in January 2006, the Extended RTC balance ($325 million as of December 31, 2005) was reduced on January 1, 2006 by $75 million by accelerating the application of the Company's accumulated cost of removal regulatory liability against the Extended RTC balance. In accordance with the RCP, the recovery periods for the aggregate of the regulatory transition costs and the Extended RTC amounts were adjusted so that recovery of these aggregate amounts through the Company's RTC rate component began on January 1, 2006, with full recovery expected to be completed as of December 31, 2008. At the end of the recovery period, any remaining unamortized regulatory transition costs and Extended RTC balances will be eliminated, first, by applying any remaining cost of removal regulatory liability balance; any remaining regulatory transition costs and Extended RTC balances would be written off. 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 9 for further discussion of the recovery of the shopping incentives and the new cost deferrals.

Transition Cost Amortization-

The Company amortizes transition costs (see Note 9) 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:

Amortization
Period	Amortization
	(In millions)
2007	$	179
2008		208
Total Amortization	$	387

(B) CASH AND SHORT-TERM FINANCIAL INSTRUMENTS-

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

(C) REVENUES AND RECEIVABLES-

The Companies' principal business is providing electric service to customers in Ohio and Pennsylvania. The Companies' retail customers are metered on a cycle basis. Electric revenues are recorded based on energy delivered through the end of the calendar month. An estimate of unbilled revenues is calculated to recognize electric service provided between the last meter reading and the end of the month. This estimate includes many factors including 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 Companies accrue the estimated unbilled amount receivable as revenue and reverse the related prior period estimate.

29

Receivables from customers include sales to residential, commercial and industrial customers and sales to wholesale customers. There was no material concentration of receivables as of December 31, 2006, with respect to any particular segment of the Companies' customers. Total customer receivables were $235 million (billed - $127 million and unbilled - $108 million) and $291 million (billed - $177 million and unbilled - $114 million) as of December 31, 2006 and 2005, respectively.

The Company sells substantially all of its retail customer receivables to OES Capital, a wholly owned subsidiary of OE. The receivables financing agreement expires on December 5, 2007.

(D)UTILITY PLANT AND DEPRECIATION-

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

The Companies provide for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annual composite rate for the Company's electric plant was approximately 2.8% in 2006, 2.1% in 2005 and 2.3% in 2004. The annual composite rate for Penn's electric plant was approximately 2.6% in 2006, 2.4% in 2005 and 2.2% in 2004.

Asset Retirement Obligations

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

(E)ASSET IMPAIRMENTS-

Long-Lived Assets-

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

Investments-

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 5(B) and (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 as of December 31, 2006, except those resulting from transactions with FirstEnergy and preferred stockholders. As of December 31, 2006, AOCL consisted of a net liability for unfunded retirement benefits due to the implementation of SFAS 158, net of tax benefits (see Note 3) of $9 million and unrealized gains on investments in securities available for sale of $12 million. As of December 31, 2005, AOCI consisted of unrealized gains on investments in securities available for sale of $4 million.

30

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

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

(H) INCOME TAXES-

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

(I)TRANSACTIONS WITH AFFILIATED COMPANIES-

Operating revenues, operating expenses and other income include transactions with affiliated companies, primarily ATSI, FES, NGC and FESC. The Ohio transition plan resulted in the corporate separation of FirstEnergy's regulated and unregulated operations in 2001. In the fourth quarter of 2005, the Companies, CEI and TE completed the intra-system transfers of their generation assets to FGCO and NGC (see Note 14). This resulted in the elimination of the fossil generating units lease arrangement and the nuclear generation PSA revenues with the exception of those revenues related to the leasehold interests (see Note 6) which were not included in the transfer. The Companies are now receiving interest income from FGCO and NGC on the associated companies notes received in exchange for the transferred net assets. The Companies continue to purchase their power from FES to meet their PLR obligations (see Note 9 for further discussion). The primary affiliated companies transactions are as follows:

	2006		2005		2004
	(In millions)
Revenues:
PSA revenues from FES	$	80	$	355	$	416
Generating units rent from FES		-		146		178
Ground lease with ATSI		12		12		12
Expenses:
Purchased power under PSA		1,264		938		970
FESC support services		94		90		91
Other Income:
Interest income from ATSI		15		16		16
Interest income from FGCO and NGC		59		9		9
Interest income from FirstEnergy		25		22		-

31

FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Companies from FESC, a subsidiary of FirstEnergy. The majority of costs are directly billed or assigned at no more than cost. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas developed by FESC. The current allocation or assignment formulas used and their bases include multiple factor formulas: each company's proportionate amount of FirstEnergy's aggregate direct payroll, number of employees, asset balances, revenues, number of customers, other factors and specific departmental charge ratios. Management believes that these allocation methods are reasonable. Intercompany transactions with FirstEnergy and its other subsidiaries are generally settled under commercial terms within thirty days.

3. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS:

                   FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees. The trusteed plans provide defined benefits based on years of service and compensation levels. 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 (Companies? share was $20 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 Companies recognize the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. During 2006, FirstEnergy amended the OPEB plan effective in 2008 to cap the monthly contribution for many of the retirees and their spouses receiving subsidized healthcare coverage. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement for disability related benefits.

                    Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans and earnings on plan assets. Such factors may be further affected by business combinations which impact employee demographics, plan experience and other factors. Pension and OPEB costs may also be affected by changes in key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations and pension and OPEB costs. FirstEnergy uses a December 31 measurement date for its pension and OPEB plans. The fair value of the plan assets represents the actual market value as of December 31, 2006.

    In December 2006, FirstEnergy adopted SFAS 158. This Statement requires an employer to recognize an asset or liability for the overfunded or underfunded status of their pension and other postretirement benefit plans. For a pension plan, the asset or liability is the difference between the fair value of the plan?s assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan?s assets and the accumulated postretirement benefit obligation. The Statement required employers to recognize all unrecognized prior service costs and credits and unrecognized actuarial gains and losses in AOCL, net of tax. Such amounts will be adjusted as they are subsequently recognized as components of net periodic benefit cost or income pursuant to the current recognition and amortization provisions. OE?s incremental impact of adopting SFAS 158 was a decrease of $231 million in pension assets, a decrease of $200 million in pension liabilities and a decrease in AOCL of $9 million, net of tax.

32

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

Obligations and Funded Status	Pension Benefits						Other Benefits
As of December 31	2006			2005			2006			2005
	(In millions)
Change in benefit obligation
Benefit obligation as of January 1	$	4,750		$	4,364		$	1,884		$	1,930
Service cost		83			77			34			40
Interest cost		266			254			105			111
Plan participants? contributions		-			-			20			18
Plan amendments		3			15			(620	)		(312	)
Medicare retiree drug subsidy		-			-			6			-
Actuarial (gain) loss		33			310			(119	)		197
Benefits paid		(274	)		(270	)		(109	)		(100	)
Benefit obligation as of December 31	$	4,861		$	4,750		$	1,201		$	1,884
Change in fair value of plan assets
Fair value of plan assets as of January 1	$	4,524		$	3,969		$	573		$	564
Actual return on plan assets		567			325			69			33
Company contribution		-			500			54			58
Plan participants? contribution		-			-			20			18
Benefits paid		(273	)		(270	)		(109	)		(100	)
Fair value of plan assets as of December 31	$	4,818		$	4,524		$	607		$	573
Funded status	$	(43	)	$	(226	)	$	(594	)	$	(1,311	)
Accumulated benefit obligation	$	4,447		$	4,327
Amounts Recognized in the Statement of
Financial Position
Noncurrent assets	$	-		$	1,023		$	-		$	-
Current liabilities		-			-			-			-
Noncurrent liabilities		(43	)		-			(594	)		(1,057	)
Net pension asset (liability) as of December 31	$	(43	)	$	1,023		$	(594	)	$	(1,057	)
Companies? share of net pension asset (liability) at end of year	$	68		$	225		$	(167	)	$	(291	)
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
Companies? share of net periodic cost (credit)	$	(6	)	$	-		$	7		$	17		$	28		$	28
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 Companies? pension trusts. The long-term rate of return is developed considering the portfolio?s asset allocation strategy.

FirstEnergy employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return on plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalization funds. Other assets such as real estate are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.

Assumed Health Care Cost Trend Rates
As of December 31	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. ESOP:

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

5.       FAIR VALUE OF FINANCIAL INSTRUMENTS:

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

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

	2006				2005
	Carrying		Fair		Carrying		Fair
		Value		Value		Value		Value
	(In millions)
Long-term debt	$	1,294	$	1,337	$	1,306	$	1,308

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

(B) INVESTMENTS-

Investments other than cash and cash equivalents include held-to-maturity securities and available-for-sale securities. The Company periodically evaluates its investments for other-than-temporary impairment. They first consider their intent and ability to hold the investment until recovery and then consider, among other factors, the duration and the extent to which the security?s fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating investments for impairment. The following table provides the approximate fair value and related carrying amounts of investments excluding nuclear decommissioning trust funds and investments of $35 million and $41 million for 2006 and 2005, respectively, 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	$	1,219	$	1,251	$	1,758	$	1,798
Lease obligation bonds		291		325		326		368
Equity securities		3		3		3		3
	$	1,513	$	1,579	$	2,087	$	2,169

.

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The fair value of notes receivables represents the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. The investments in lease obligation bonds are accounted for as held-to-maturity securities and the fair value is based on present value of the cash inflows based on the yield to maturity similar to the notes receivable. The maturities range from the 2007 to 2017.

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

	2006								2005
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
	(In millions)
Debt securities	$	291	$	34	$	-	$	325	$	326	$	42	$	-	$	368
Equity securities		3		-		-		3		3		-		-		3
	$	294	$	34	$	-	$	328	$	329	$	42	$	-	$	371

 There were no proceeds from the sale of investments, realized gains and losses on those sales, or interest and dividend income for the three years ended December 31, 2006 for the above investments:

(C)NUCLEAR DECOMMISSIONING TRUST FUND INVESTMENTS-

Decommissioning trust investments are classified as available-for-sale. As part of the intra-system nuclear generation asset transfers in the fourth quarter of 2005, the Companies transferred their decommissioning trust investments to NGC with the exception of a portion related to OE?s leasehold interests in the nuclear generation assets retained by the Company. The Companies have 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 $2 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 carrying value, which equals the fair value of the nuclear decommissioning trust funds as of December 31, 2006 and 2005, respectively:

		2006		2005
Debt securities	(In millions)
?Government obligations		$	25	$	32
?Corporate debt securities			6		5
?Mortgage-backed securities			7		-
			38		37
Equity securities			80		67
		$	118	$	104

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	$	38	$	-	$	-	$	38	$	37	$	-	$	-	$	37
Equity securities		61		19		-		80		61		9		3		67
	$	99	$	19	$	-	$	118	$	98	$	9	$	3	$	104

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	$	39	$	227	$	154
Gross realized gains		1		35		25
Gross realized losses		1		7		7
Interest and dividend income		3		13		13

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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.

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

6. LEASES:

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

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

Consistent with the regulatory treatment, the rentals for capital and operating leases are charged to operating expenses on the Consolidated Statements of Income. Such costs for the three years ended December 31, 2006, are summarized as follows:

	2006		2005		2004
	(In millions)
Operating leases
Interest element	$	87.1	$	93.3	$	94.8
Other		57.5		52.3		50.4
Capital leases
Interest element		0.3		0.8		1.0
Other		1.3		1.9		1.6
Total rentals	$	146.2	$	148.3	$	147.8

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

			Operating Leases
					PNBV
	Capital		Lease		Capital
	Leases		Payments		Trusts		Net
	(In millions)
2007	$	0.1	$	146.1	$	59.9	$	86.2
2008		0.1		147.3		34.9		112.4
2009		0.1		147.6		42.1		105.5
2010		0.1		148.3		43.2		105.1
2011		0.1		147.3		42.7		104.6
Years thereafter		0.5		750.3		193.5		556.8
Total minimum lease payments		1.0	$	1,486.9	$	416.3	$	1,070.6
Executory costs		-
Net minimum lease payments		1.0
Interest portion		0.6
Present value of net minimum lease payments		0.4
Less current portion		0.1
Noncurrent portion	$	0.3

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

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7. VARIABLE INTEREST ENTITIES:

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

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

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

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

The Company is exposed to losses under the sale-leaseback agreements upon the occurrence of certain contingent events that it considers unlikely to occur. The Company has a maximum exposure to loss under these provisions of $835 million, which represents the net amount of casualty value payments upon the occurrence of specified casualty events that render the applicable plant worthless. Under the sale and leaseback agreement, the Company has net minimum discounted lease payments of $632 million that would not be payable if the casualty value payments are made.

8.  OHIO TAX LEGISLATION:

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

9.  REGULATORY MATTERS:

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.

38

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

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

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

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

The ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils completed the consolidation of these regions into a single new regional reliability organization known as ReliabilityFirst Corporation. ReliabilityFirst began operations as a regional reliability council under NERC on January 1, 2006 and on November 29, 2006 filed a proposed Delegation Agreement with NERC to obtain certification consistent with the final rule as a ?regional entity? under the ERO. All of FirstEnergy?s facilities are located within the ReliabilityFirst region.

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

39

FirstEnergy believes it is in compliance with all current NERC reliability standards. However, based upon a review of the October 20, 2006 NOPR, it appears that the FERC will adopt more strict reliability standards than those contained in the current NERC standards. The financial impact of complying with the new standards cannot be determined at this time. However, the EPACT required that all prudent costs incurred to comply with the new reliability standards be recovered in rates.. If FirstEnergy is unable to meet the reliability standards for its bulk power system in the future, it could have a material adverse effect on FirstEnergy?s and its subsidiaries? financial condition, results of operations and cash flows.

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

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 $75 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 TE?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:

40

Recognize fuel and distribution deferrals commencing January 1, 2006;

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

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

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

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

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

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

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

On December 29, 2005, the FERC issued an order setting the two power sales agreements 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 agreements. 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 and the Ohio Companies, Penn, 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.

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The terms of the settlement provide for modification of both the Ohio and Penn power supply agreements with FES. Under the Ohio 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. In addition, pursuant to the settlement, the wholesale rate charged by FES under the Penn power supply agreement can be no greater than the generation component of charges for retail PLR load in Pennsylvania. The modifications to the Ohio and Pennsylvania power supply agreements became effective January 1, 2006. The Penn supply agreement subject to the settlement expired at midnight on December 31, 2006.

As a result of Penn?s PLR competitive solicitation process approved by the PPUC for the period January 1, 2007 through May 31, 2008, FES was selected as the winning bidder for a number of the tranches for individual customer classes. The balance of the tranches will be supplied by unaffiliated power suppliers. On October 2, 2006, FES filed an application with the FERC under Section 205 of the Federal Power Act for authorization to make these affiliate sales to Penn. Interventions or protests were due on this filing on October 23, 2006. Penn was the only party to file an intervention in this proceeding. This filing was accepted by the FERC on November 15, 2006, and no requests for rehearing were filed.

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.

10.CAPITALIZATION:

   (A) RETAINED EARNINGS-

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

   (B) PREFERRED AND PREFERENCE STOCK-

The Company has eight million authorized and unissued shares of $25 par value preferred stock and eight million authorized and unissued shares of preference stock with no par value.

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

 Other Long-term Debt-

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

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Based on the amount of FMB authenticated by the respective mortgage bond trustees through December 31, 2006, the Companies? annual sinking fund requirements for all FMB issued under the various mortgage indentures amounts to $38 million. The Companies expect to deposit funds with their respective mortgage bond trustees in 2007 that will then be withdrawn upon the surrender for cancellation of a like principal amount of FMB, specifically authenticated for such purposes against unfunded property additions or against previously retired FMB. This method can result in minor increases in the amount of the annual sinking fund requirement. The sinking fund required under the Company?s 1930 indenture is no longer required starting January 1, 2007, as this indenture has been satisfied.

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

	(In millions)
2007	$	160
2008		179
2009		2
2010		65
2011		1

Included in the 2007 amount are $156 million for variable interest rate pollution control revenue bonds that have provisions by which individual debt holders are required to "put back" the respective debt to the issuer for redemption prior to its maturity date. This amount represents the next time the debt holders may exercise this provision.

The Companies' obligations to repay certain pollution control revenue bonds are secured by several series of FMB. Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank LOCs of $158 million and noncancelable municipal bond insurance policies of $123 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the LOCs or the policies, the Companies are entitled to a credit against their obligation to repay those bonds. The Companies pay annual fees of 1.7% of the amounts of the LOCs to the issuing bank and 0.214% to 0.230% of the amounts of the policies to the insurers and are obligated to reimburse the bank or insurers, as the case may be, for any drawings thereunder.

11. 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 Companies. The generating plant interests transferred do not include leasehold interests of the Company that are currently subject to sale and leaseback arrangements with non-affiliates (See Note 14). As a result, only the ARO associated with sale and leaseback arrangements remain with the Company.

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

The Company continues to maintain the nuclear decommissioning trust funds associated with the sale and leaseback arrangements that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of December 31, 2006, the fair value of the decommissioning trust assets was $118 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.

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The Company identified applicable legal obligations as defined under the new standard at its retired generating units, substation control rooms, service center buildings, line shops and office buildings, identifying asbestos as the primary conditional ARO. As a result of adopting FIN 47 in December 2005, the Company recorded a conditional ARO liability of $27 million (including accumulated accretion for the period from the date the liability was incurred to the date of adoption), an asset retirement cost of $9 million (recorded as part of the carrying amount of the related long-lived asset) and accumulated depreciation of $9 million. The Company recognized a regulatory liability of $1 million upon adoption of FIN 47 for the transition amounts related to establishing the ARO for asbestos removal from substation control room and service center buildings, therefore requiring a $26 million cumulative effect adjustment ($16 million net of tax) for unrecognized depreciation and accretion to be recorded as of December 31, 2005. The obligation to remediate asbestos, lead paint abatement and other remediation costs at the retired generating units was developed based on site specific studies performed by an independent engineer. The costs of remediation at the substation control rooms, service center buildings, line shops and office buildings were based on costs incurred during recent remediation projects performed at each of these locations, respectively. The conditional ARO liability was the developed utilizing an expected cash flow approach (as discussed in SFAC 7) to measure the fair value of the ARO. The Company used a probability weighted analysis to estimate when remediation payments would begin. The effect on income as if FIN 47 had been applied during 2004 is immaterial.

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

	2006		2005
ARO Reconciliation	(In millions)
Balance at beginning of year	$	83	$	339
Transfers to FGCO and NGC		-		(293	)
Accretion		5		21
Revisions in estimated cash flows		-		(11	)
FIN 47 ARO upon adoption		-		27
Balance at end of year	$	88	$	83

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

Short-term borrowings outstanding as of December 31, 2006, consisted of $3 million of OE bank borrowings and $114 million of borrowings from affiliates. OES Capital is a wholly owned subsidiary of the Company whose borrowings are secured by customer accounts receivable purchased from the Company. OES Capital can borrow up to $170 million under a receivables financing arrangement at rates based on certain bank commercial paper and is required to pay an annual fee of 0.15% on the amount of the entire finance limit. The receivables financing agreement expires on December 5, 2007.. Penn Funding, a wholly owned subsidiary of Penn, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Penn. It can borrow up to $25 million under a receivables financing arrangement at rates based on bank commercial paper rates. The financing arrangements require payment of an annual facility fee of 0.13% on the entire finance limit. Penn's receivables financing agreements expire on June 28, 2007. As separate legal entities with separate creditors, OES Capital and Penn Funding would have to satisfy their separate obligations to creditors before any of their remaining assets could be made available to the Companies, respectively. As of December 31, 2006, both facilities were undrawn.

    On August 24, 2006,FirstEnergy, the Companies, CEI, TE, 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 $500 million and Penn?s is $50 million, subject in each case to applicable regulatory approvals. The weighted average interest rates on short-term borrowings outstanding as of December 31, 2006 and 2005 were 4.0% and 4.2%, respectively.

13.COMMITMENTS AND CONTINGENCIES:

(A)  NUCLEAR INSURANCE-

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

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The Company is also insured as to its respective leasehold interests in Beaver Valley Unit 2 and Perry under policies issued to NGC. Under these policies, up to $2.75 billion is provided for property damage and decontamination and decommissioning costs. The Company has also obtained approximately $167.8 million of insurance coverage for replacement power costs for its respective leasehold interests in Beaver Valley Unit 2 and Perry. Under these policies, the Company can be assessed a maximum of approximately $6.6 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses.

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

(B)  ENVIRONMENTAL MATTERS-

The Companies accrue 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 Companies? determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.

W. H. Sammis Plant

In 1999 and 2000, the EPA issued NOV or compliance orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as the New Source Review cases.

On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the New Source Review litigation. This settlement agreement, which is in the form of a consent decree, was approved by the Court on July 11, 2005, and requires reductions of NO_X and SO₂ emissions at the W. H. Sammis Plant and other coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if we fail to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, we could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation are currently estimated to be $1.5 billion ($400 million of which is expected to be spent in 2007, with the largest portion of the remaining $1.1 billion expected to be spent in 2008 and 2009).

The Sammis NSR Litigation consent decree also requires us to spend up to $25 million toward environmentally beneficial projects, $14 million of which is satisfied by entering into 93 MW (or 23 MW if federal tax credits are not applicable) of wind energy purchased power agreements with a 20-year term. An Initial 16 MW of the 93 MW consent decree obligation  was satisfied during 2006.

On August 26, 2005, FGCO entered into an agreement with Bechtel under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of SO₂ emissions. FGCO also entered into an agreement with B&W on August 25, 2006 to supply flue gas desulfurization systems for the reduction of SO₂ emissions. Selective Catalytic Reduction (SCR) systems for the reduction of NOx emissions also are being installed at the W.H. Sammis Plant under a 1999 agreement with B&W.

OE and Penn agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 included the penalties paid by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized liabilities in the first quarter of 2005 of $9.2 million and $0.8 million, respectively, for probable future cash contributions toward environmentally beneficial projects.

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(C)OTHER LEGAL PROCEEDINGS-

Power Outages and Related Litigation

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

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

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

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

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Other Legal Matters

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

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

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

14.     FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS:

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

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

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

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

The purchase price of the generation assets was the net book value as of September 30, 2005. The difference (approximately $20.5 million) between the purchase price and the net book value at the date of transfer was credited to equity. Pursuant to the OE Contribution Agreement, OE made a capital contribution to NGC of its undivided ownership interests in certain nuclear generation assets, the common stock of OES Nuclear Incorporated (OES Nuclear), a wholly owned subsidiary of OE that held an undivided interest in the Perry Nuclear Power Plant, together with associated decommissioning trust funds and other related assets. In connection with the contribution, NGC assumed other liabilities associated with the transferred assets. In addition, OE and Penn received promissory notes from NGC in the principal amount of approximately $371.5 million and $240.4 million, respectively, representing the net book value of the contributed assets as of September 30, 2005, less other liabilities assumed. The notes bear interest at a rate per annum based on OE?s and Penn's weighted average cost of long-term debt (3.98% and 5.39%, respectively), mature twenty years from the date of issuance, and are subject to prepayment at any time, in whole or in part, by NGC. Following the capital contribution, OES Nuclear was merged with and into NGC, and OE distributed the common stock of NGC as a dividend (approximately $106.8 million) to FirstEnergy, such that NGC is currently a direct wholly owned subsidiary of FirstEnergy. In December 2006, OE and Penn recorded a purchase price adjustment of $87.9 million for the nuclear generation asset transfer to adjust intercompany notes and equity accounts to reflect a change in the agreed upon value for the asset retirement obligations that were assumed by NGC.

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

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

The following table provides the value of assets transferred in 2005 along with the related liabilities:

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

15.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 Companies are currently evaluating the impact of this Statement on their 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.

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This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. The Companies are currently evaluating the impact of this Statement on their 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 is currently evaluating the impact of this Statement. The Companies do not expect this Statement to have a material impact on their financial statements.

16.       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	$	582.2	$	573.1	$	673.7	$	594.5
Expenses		499.4		493.8		622.9		520.3
Operating Income		86.8		79.3		50.8		74.2
Other Income		15.3		14.9		10.6		3.0
Income Before Income Taxes		102.1		94.2		61.4		77.2
Income Taxes		38.3		35.0		17.9		32.1
Net Income	$	63.8	$	59.2	$	43.5	$	45.1
Earnings on Common Stock	$	63.2	$	55.6	$	43.4	$	44.8

Three Months Ended	March 31, 2005			June 30, 2005		September 30, 2005		December 31,  2005
	(In millions)
Revenues	$	726.3		$	716.6	$	825.8	$	706.8
Expenses		598.3			576.1		600.4		568.2
Operating Income		128.0			140.5		225.4		138.6
Other Income (Expense)		(17.8	)		1.2		11.3		13.1
Income Before Income Taxes		110.2			141.7		236.7		151.7
Income Taxes		53.4			94.6		105.3		56.6
Income Before Cumulative Effect of a Change in Accounting Principle		56.8			47.1		131.4		95.1
Cumulative Effect of a Change in Accounting Principle (Net of Income Taxes) (Note 2(G))		-			-		-		16.3
Net Income	$	56.8		$	47.1	$	131.4	$	78.8
Earnings on Common Stock	$	56.1		$	46.4	$	130.7	$	78.1

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