EXHIBIT 99.1

FIRSTENERGY SOLUTIONS CORP.

2006 ANNUAL REPORT TO STOCKHOLDERS

FirstEnergy Solutions Corp. (FES) is a wholly owned subsidiary of FirstEnergy Corp. FES provides energy-related products and services primarily in Ohio, Pennsylvania, Michigan, Maryland and New Jersey, and through its subsidiaries, FirstEnergy Generation Corp. and FirstEnergy Nuclear Generation Corp., owns and operates FirstEnergy’s non-nuclear generation facilities and owns FirstEnergy’s nuclear generation facilities, respectively. FirstEnergy Nuclear Operating Company continues to operate and maintain the nuclear generating facilities.

Contents	Page
Glossary of Terms	i-ii
Report of Independent Auditors	1
Selected Financial Data	2
Management's Discussion and Analysis of Results of Operations and Financial Condition	3-22
Consolidated Statements of Income	23
Consolidated Balance Sheets	24
Consolidated Statements of Capitalization	25
Consolidated Statements of Common Stockholder's Equity	26
Consolidated Statements of Cash Flows	27
Notes to Consolidated Financial Statements	28-49

GLOSSARY OF TERMS

The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries:

ATSI	American Transmission Systems, Inc., owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
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, a New Jersey electric utility operating subsidiary
Met-Ed	Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
NGC	FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities
OE	Ohio Edison Company, an Ohio electric utility operating subsidiary
Ohio Companies	CEI, OE and TE
Penelec	Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Penn	Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
The following abbreviations and acronyms are used to identify frequently used terms in this report:
AOCI	Accumulated Other Comprehensive Income
ARO	Asset Retirement Obligation
B&W	Babcock & Wilcox Company
CAIR	Clean Air Interstate Rule
CAL	Confirmatory Action Letter
CAMR	Clean Air Mercury Rule
CAT	Commercial Activity Tax
CBP	Competitive Bid Process
CO2	Carbon Dioxide
DOJ	United States Department of Justice
ECAR	East Central Area Reliability Coordination Agreement
EITF	Emerging Issues Task Force
EITF 99-19	EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent"
EPA	Environmental Protection Agency
EPACT	Energy Policy Act of 2005
ERO	Electric Reliability Organization
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
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.”
FSP	FASB Staff Position
FSP SFAS 115-1 and SFAS 124-1	FSP SFAS 115-1 and SFAS 124-1, “The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments.”
GAAP	Accounting Principles Generally Accepted in the United States
GAT	Intra-system transfer of non-nuclear generation and nuclear generation assets
GHG	Greenhouse Gases
KWH	Kilowatt-hours
LOC	Letter of Credit

i

GLOSSARY OF TERMS, Cont'd.

MISO	Midwest Independent System Transmission Operator, Inc.
Moody’s	Moody’s Investors Service
MSSF	Morgan Stanley Senior Funding, Inc.
MW	Megawatts
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NOPR	Notice of Proposed Rulemaking
NOV	Notices of Violation
NOX	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
NUG	Non-Utility Generation
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
PJM	PJM Interconnection L.L.C.
PLR	Provider of Last Resort
PPUC	Pennsylvania Public Utility Commission
PSA	Power Supply Agreement
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act of 1935
RFP	Request for Proposal
RTO	Regional Transmission Organization
RTOR	Regional Through and Out Rates
S&P	Standard & Poor’s Ratings Service
SEC	U.S. Securities and Exchange Commission
SECA	Seams Elimination Cost Adjustment
SFAS	Statement of Financial Accounting Standards
SFAS 87	SFAS No. 87, “Employers’ Accounting for Pensions”
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 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 142	SFAS No. 142, “Goodwill and Other Intangible Assets”
SFAS 143	SFAS No. 143, “Accounting for Asset Retirement Obligations”
SFAS 144	SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”
SFAS 157	SFAS No. 157, “Fair Value Measurements”
SFAS 158	SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB Statements Nos. 87, 88, 106, and 132(R)”
SFAS 159	SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115.”
SIP	State Implementation Plan(s) Under the Clean Air Act
SO2	Sulfur Dioxide

ii

Report of Independent Auditors

To the Stockholder and Board of Directors of

FirstEnergy Solutions Corp.

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of FirstEnergy Solutions Corp. 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 audit in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 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(H) and Note 8 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

April 11, 2007

1

The following selected financial data should be read in conjunction with, and is qualified in its entirety by reference to, the section 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.

FIRSTENERGY SOLUTIONS CORP.
SELECTED FINANCIAL DATA
For the Years Ended December 31,	2006			2005			2004
	(Dollars in thousands)
Revenues (1)	$	4,011,353		$	3,967,239		$	5,206,161
Operating Income	$	778,145		$	470,475		$	665,116
Income From Continuing Operations	$	418,653		$	208,560		$	322,239
Net Income	$	418,653		$	205,167		$	326,635
Total Assets	$	7,999,007		$	7,100,490		$	6,314,775
Capitalization as of December 31:
Common Stockholder's Equity	$	1,859,363		$	1,401,334		$	949,334
Long-Term Debt		1,614,222			2,615,247			2,600,244
Total Capitalization	$	3,473,585		$	4,016,581		$	3,549,578
Capitalization Ratios:
Common Stockholder's Equity		53.5	%		34.9	%		26.7	%
Long-Term Debt		46.5			65.1			73.3
Total Capitalization		100.0	%		100.0	%		100.0	%
(1) The reduction of revenues subsequent to 2004 reflects a change in reporting methodology for PJM market         transactions (see Note 2(C)) that had no impact on net income.

2

FIRSTENERGY SOLUTIONS CORP.

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, 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 EPACT (including, but not limited to, the repeal of the PUHCA), 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 SEC and the NRC as disclosed in FirstEnergy’s SEC filings, the continuing availability and operation of generating units, the ability of our generating units to continue to operate at, or near full capacity, 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, the ability to access the public securities and other capital markets and the cost of such capital, the successful structuring and completion of a potential sale and leaseback transaction for Bruce Mansfield Unit 1 currently under consideration by management, the risks and other factors discussed from time to time in FirstEnergy’s SEC filings, and other similar factors. Also, a security rating is not a recommendation to buy, sell or hold securities, and it may be subject to revision or withdrawal at any time and each such rating should be evaluated independently of any other rating. We expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events, or otherwise.

GENERAL

We were organized under the laws of the State of Ohio in 1997 as a wholly owned subsidiary of FirstEnergy. We provide energy-related products and services to wholesale and retail customers in the MISO and PJM markets. We also own and operate, through our subsidiary, FGCO, FirstEnergy’s fossil and hydroelectric generating facilities and own, through our subsidiary, NGC, FirstEnergy’s nuclear generating facilities. FENOC, a separate subsidiary of FirstEnergy, operates and maintains NGC’s nuclear generating facilities. In addition to the generation output of the facilities owned by FGCO and NGC, we purchase the output relating to leasehold interests of OE, CEI and TE in certain of those facilities that are subject to sale and leaseback arrangements with non-affiliates, pursuant to full-output, cost-of-service power sale agreements.

FirstEnergy is a diversified energy company headquartered in Akron, Ohio. Its subsidiaries and affiliates are involved in the generation, transmission and/or distribution of electricity, as well as energy management and other energy-related services. Its eight electric utility operating companies - ATSI, OE, CEI, TE, Penn, Met-Ed, Penelec and JCP&L - comprise the nations’ fifth largest investor-owned electric system, serving 4.5 million retail customers within a 36,100-square-mile area of Ohio, Pennsylvania and New Jersey.

Revenues are primarily from the sale of electricity (provided from our generating facilities and through purchased power arrangements) to affiliated utility companies to meet all or a portion of their PLR requirements. These affiliated power sales include a full-requirements PSA with OE, CEI and TE to supply each of their PLR obligations through 2008, at prices that take into consideration their respective PUCO authorized billing rates. Our PSA to satisfy Penn’s PLR power requirements expired on December 31, 2006. As further discussed under “Power Supply Agreements with Regulated Affiliates”, we were the winning bidder for a portion of Penn’s PLR competitive solicitation process for the period January 1, 2007 through May 31, 2008. We also have a partial requirements wholesale power sales agreement with our affiliates, Met-Ed and Penelec, to supply a portion of each of their respective PLR obligations at fixed prices through 2010. Our revenues also include competitive retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania, Maryland and Michigan.

ACQUISITION OF GENERATION ASSETS FROM AFFILIATES

In the fourth quarter of 2005, the Ohio Companies and Penn completed the intra-system transfer of non-nuclear generation and nuclear generation assets (GAT) to FGCO and NGC, respectively. See Note 1 for further discussion. 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, without impacting the operation of the plants. The generating plant interests transferred do not include leasehold interests of CEI, TE and OE in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates. FENOC continues to operate and maintain the nuclear generation assets.

3

Prior to completion of the GAT in the fourth quarter of 2005, we, through our subsidiary, FGCO, operated FirstEnergy’s non-nuclear generation businesses. Our pre-GAT historical results reflected the related non-nuclear generation fuel and operating costs as well as certain transactions and relationships with our affiliates. These included PSAs to provide electricity to the Ohio Companies and Penn to meet their PLR obligations, lease arrangements for their non-nuclear generation assets and purchased power agreements for their nuclear generation. The Ohio Companies and Penn reflected the nuclear fuel and operating costs and depreciation and property tax expenses related to their nuclear and non-nuclear generation assets in their pre-GAT historical results.

Our consolidated financial statements and those of our subsidiaries as of December 31, 2006 and 2005 and for the years ended December 31, 2006, 2005 and 2004 represent the financial position, results of operations and cash flows as if the GAT had occurred as of December 31, 2003. Certain financial results, net assets and net cash flows related to the ownership of OE, Penn, CEI and TE of the transferred generation assets prior to the GAT are reflected in these consolidated financial statements. The revisions in certain affiliated company transactions and relationships that had existed prior to the GAT, which are discussed above, have been reflected for the three years ended December 31, 2006, 2005 and 2004 as if the GAT had been effective as of December 31, 2003. Those changes in our historical results and cash flows that began in the fourth quarter of 2005 have been estimated on an annualized basis and assumed to have begun at the end of 2003 and are reflected in the 2004 and 2005 financial statements. Our results in 2006 reflect a full year of the GAT changes and, therefore, no allocations or adjustments, except for those related to the NGC corporate restructuring discussed below, were reflected in the 2006 financial statements.

On December 28, 2006, the NRC approved the transfer of ownership in NGC from FirstEnergy to us. Effective December 31, 2006, NGC is our wholly owned subsidiary and a second tier subsidiary of FirstEnergy. FENOC continues to operate and maintain the nuclear generation assets. The consolidated financial statements assume that this corporate restructuring occurred at the end of 2003, with our and NGC’s financial position and results combined at the end of 2003 and associated company transactions and balances eliminated in consolidation.

RESULTS OF OPERATIONS

Overview

Net income in 2006 increased to $419 million from $205 million in 2005. The increase in net income was primarily due to lower purchased power costs and increased revenues from power sales to affiliates. Net income in 2005 included an after-tax charge to income of $9 million from the cumulative effect of a change in accounting principle due to the adoption of FIN 47 in December 2005 (see Note 2(H)) and $5 million of results from discontinued operations. Income before discontinued operations and the cumulative effect of an accounting change was $209 million in 2005.

Net income in 2005 decreased by $122 million to $205 million from $327 million in 2004. The net income decrease primarily resulted from lower wholesale power sales to affiliates and higher fuel costs, nuclear operating costs and interest expense partially offset by lower fossil generation operating costs and increased retail electric sales compared to 2004. Net income in 2004 included $4 million of results from discontinued operations. Income before discontinued operations was $322 million in 2004.

Revenues

Revenues increased by $44 million in 2006 compared to the prior year due to increases in affiliated power sales which were partially offset by decreased non-affiliated generation sales. Affiliated power sales to the Ohio Companies and Penn through PSA arrangements increased by $567 million primarily as a result of higher unit prices. The higher unit prices resulted from the PSA provision under which our PSA revenue unit prices reflected increases in the Ohio Companies’ retail generation sales unit prices. The PSA revenue increase also reflected a 3.2% increase in sales resulting from the Ohio Companies’ higher retail generation sales requirements. The higher PSA sales revenues were partially offset by a $383 million decrease in power sales to our affiliates in the PJM market. This decrease was due to a 50.9% decrease in KWH sales and lower unit prices. The lower sales were due to lower contractual sales requirements with our PJM market affiliates and to decreased generation sales requirements in the JCP&L service area in 2006 compared to 2005.

Non-affiliated generation sales revenues decreased in both the retail and wholesale markets. The lower retail sales revenues were due to a 17.3% decrease in KWH sales partially offset by higher unit prices. The lower sales reflected a decrease in the shopping customers we were serving as those customers returned to our Ohio utility affiliates for their generation requirements. The record generation output increased our generation KWH available for the wholesale market which was reflected in a 9.3% increase in wholesale KWH sales as compared to 2005. However these sales increases were more than offset by lower unit prices in the wholesale market which resulted in a revenue decrease of $78 million in 2006. Transmission revenues increased $3 million in 2006 compared to 2005.

4

An equivalent decrease in wholesale electric revenues and purchased power costs in 2005 compared to 2004 primarily resulted from our recording PJM sales and purchased power transactions on an hourly net position basis beginning in the first quarter of 2005 compared with recording each discrete transaction (on a gross basis) in 2004 (see PJM and MISO Interconnection Transactions discussed later). This change had no impact on our net income and resulted from the dedication of the generation output of the Beaver Valley Power Station to PJM in January 2005. Wholesale electric revenues and purchased power costs in 2004 were each $1.1 billion higher due to recording those transactions on a gross basis.

Excluding the effect of the change in recording PJM wholesale transactions on a gross basis in 2004 ($1.1 billion), revenues decreased by $171 million in 2005 as compared to 2004. A decrease of $210 million in power sales to affiliates was partially offset by an $18 million increase in non-affiliated generation sales. The affiliated power sales decrease consisted of decreases in sales to the PJM market affiliates and in PSA sales of $169 million and $41 million, respectively. The lower PJM market sales revenues resulted from a 19.2% decrease in KWH sales (primarily in sales to Met-Ed and Penelec) which was partially offset by higher unit prices. The PSA revenues decrease resulted from lower unit prices partially offset by a 2.0% KWH sales increase reflecting increased affiliated utilities’ sales requirements.

Non-affiliated generation sales revenues increased $18 million in 2005 compared to 2004 primarily resulting from an 8.4% average unit price increase in retail sales, partially offset by a 5.0% decrease in retail KWH sales. Revenues from wholesale sales decreased slightly (before the PJM adjustment) due to lower KWH sales that were substantially offset by higher unit prices in the wholesale market. Transmission revenues increased $26 million in 2005 compared to 2004 due primarily to higher transmission system usage.

Changes in revenues in 2006 and 2005 from the prior year are summarized in following table:

							Increase (Decrease)
Revenues by Type of Service	2006		2005		2004		2006 vs. 2005			2005 vs. 2004
	(In millions)
Non-affiliated generation sales:
Retail	$	590	$	656	$	637	$	(66	)	$	19
Wholesale(1)		676		754		755		(78	)		(1	)
Total non-affiliated sales		1,266		1,410		1,392		(144	)		18
Affiliated power sales		2,609		2,425		2,635		184			(210	)
Transmission		68		65		39		3			26
Other		68		67		72		1			(5	)
Total		4,011		3,967		4,138		44			(171	)
PJM adjustment		-		-		1,068		-			(1,068	)
Total revenues	$	4,011	$	3,967	$	5,206	$	44		$	(1,239	)
(1) Excluding 2004 effect of recording PJM transactions on a gross basis.

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The following table summarizes the price and volume factors contributing to the changes in revenue from non-affiliated and affiliated sales:

	Increase (Decrease)
Source of Change in Non-Affiliated Generation Sales	2006 vs. 2005			2005 vs. 2004
	(In millions)
Retail:
Effect of 17.3% and 5.0% decreases in volume	$	(114	)	$	(32	)
Change in prices		48			51
		(66	)		19
Wholesale:
Effect of 9.3% and (7.6)% changes in volume(1)		70			(57	)
Change in prices		(148	)		56
		(78	)		(1	)
Net change in non-affiliated generation sales	$	(144	)	$	18
(1) Decrease of 60.5% including the effect of the PJM adjustment.

	Increase (Decrease)
Source of Change in Affiliated Power Sales	2006 vs. 2005			2005 vs. 2004
	(In millions)
PSA sales:
Effect of 3.2% and 2.0% increases in volume	$	55		$	34
Change in prices		512			(75	)
		567			(41	)
PJM Market sales:
Effect of 50.9% and 19.2% decreases in volume		(377	)		(175	)
Change in prices		(6	)		6
		(383	)		(169	)
Net change in affiliated power sales	$	184		$	(210	)

Expenses

Total operating expenses and taxes decreased $264 million in 2006 compared to 2005 and decreased $1.04 billion in 2005 compared to 2004. The decrease in 2006 was primarily due to decreased purchased power costs which were partially offset by higher fuel costs. The decrease in 2005 was primarily due to reporting PJM transactions on a gross basis in 2004 and net basis in 2005.

The following table summarizes the factors contributing to the changes in fuel and purchased power costs:

	Increase (Decrease)
Source of Change in Fuel and Purchased Power	2006 vs. 2005			2005 vs. 2004
	(In millions)
Fuel:
Change due to increased unit costs	$	70		$	243
Change due to volume consumed		30			44
		100			287
Purchased Power:
Change due to increased unit costs		9			78
Change due to volume purchased		(428	)		(347	)
		(419	)		(269	)
Net Change		(319	)		18
PJM adjustment		-			(1,068	)
Net Decrease in Fuel and Purchased Power Costs	$	(319	)	$	(1,050	)

The $264 million decrease in expenses in 2006 compared to 2005 was due to the purchased power costs decrease of $419 million, which was partially offset by higher fuel costs and other operating costs of $100 million and $47 million, respectively.

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Higher fuel costs reflected the effect of the generation fleet’s record output in 2006. In particular, fossil fuel costs increased $97 million as a result of increased generation output, higher coal prices and increased transportation costs for western coal. The increased coal costs were partially offset by lower natural gas and emission allowance costs of $42 million. Nuclear fuel costs were higher by $3 million in 2006 compared to the prior year principally due to higher unit prices. Purchased power costs decreased as a result of decreased KWH purchases partially offset by increased unit prices. KWH purchases in 2006 were lower by 34% compared to 2005 reflecting the effect of reduced power sales to our affiliates in the PJM market and increased power available from our owned generation.

The increase of $47 million in other operating expenses in 2006 compared to 2005 was primarily driven by higher nuclear operating costs partially offset by lower transmission expenses and credits from the sale of emission allowances. The increase in nuclear operating expenses was due to three refueling outages in 2006 compared to two refueling outages in 2005. Transmission expenses decreased due to lower PJM congestion and ancillary charges related to the lower affiliated sales discussed above and lower MISO transmission expenses.

Excluding the effect of the $1.1 billion of PJM purchased power costs recorded on a gross basis in 2004, total expenses increased by $23 million in 2005 compared to 2004. Higher fuel costs of $287 million were substantially offset by decreased purchased power costs of $269 million.

The generation fleet established a record output in 2005. As a result, increased coal consumption and the related cost of emission allowances combined to increase fossil fuel expense in 2005 from 2004. Higher coal costs resulted from increased market purchases, higher contract coal prices and increased transportation costs. Emission allowance costs increased primarily from higher prices. To a lesser extent, fuel expense increased due to higher costs associated with the increase in generation from the fossil units relative to nuclear generation. Fossil generation output increased 12% in 2005 and nuclear output decreased by 2%, compared to 2004, due to the nuclear refueling outages discussed below. Purchased power costs decreased as a result of decreased KWH purchases partially offset by increased unit prices. The decrease in KWH purchases reflected the increased KWH available from our generating facilities and lower sales requirements in 2005.

Other operating costs increased $26 million in 2005 compared to 2004 principally due to increased nuclear and transmission costs. Non-fuel nuclear costs were higher in 2005 due to refueling outages at Perry Unit 1 (including an unplanned extension) and Beaver Valley Unit 2 and a scheduled 23-day mid-cycle inspection outage at the Davis-Besse Plant. There was only one refueling outage in 2004. Higher transmission costs of $58 million due primarily to increased loads and higher transmission system usage charges further increased other operating costs in 2005. These higher costs were partially offset by lower fossil generation costs that resulted primarily from emission allowance transactions and reduced maintenance outages in 2005.

Depreciation expense increased by $2 million in 2006 compared to 2005 as a result of property additions. The decrease of $21 million in depreciation expense in 2005 compared to 2004 was attributable to revised estimated service life assumptions for fossil generating plants.

General taxes increased by $6 million in 2006 compared to 2005 due to increased property taxes. General taxes increased by $1 million in 2005 compared to the prior year, reflecting higher KWH sales which increased gross receipts tax.

Other Expense

Total other expense decreased $14 million in 2006 compared to 2005 due to the absence of a $28 million civil penalty in 2005 payable to the DOJ related to the Davis-Besse reactor head issue and lower interest expense, partially offset by a decrease in investment income earned on the nuclear decommissioning trusts. The lower interest expense was due to the repayment of higher interest rate notes payable by assuming pollution control debt having lower interest rates.

Total other expense increased by $24 million in 2005 compared to 2004 due to the $28 million DOJ civil penalty in 2005, offset by higher investment income earned on the nuclear decommissioning trusts. In addition, interest expenses increased $15 million in 2005, compared to the prior year, due to short-term borrowings having higher interest rates.

Income Taxes

Income taxes in 2006 were higher than in 2005, principally due to higher taxable income. Income taxes in 2005 compared to 2004 decreased as a result of lower taxable income and the effect of the Ohio tax legislation discussed below.

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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 to determine the actual liability, thereby eliminating the current income-based franchise tax over a five-year period. As a result of the new tax structure, all net deferred taxes that were not expected to reverse during the five-year phase-in period were written off as of June 30, 2005. Since we were in a deferred tax liability position, the adjustment to net deferred taxes resulted in a $7 million decrease to income taxes in 2005.

Discontinued Operations

In December 2004, our retail natural gas business qualified as assets held for sale in accordance with SFAS 144. On March 31, 2005, we completed the sale for an after-tax gain of $5 million.

Net results of $5 million (including the 2005 gain on the sale of assets discussed above) and $4 million associated with the divested retail gas business for 2005 and 2004, respectively, are reported as discontinued operations on the Consolidated Statements of Income. Pre-tax operating results were $1 million and $7 million in 2005 and 2004, respectively. Revenues associated with discontinued operations for 2005 and 2004 were $146 million and $496 million, respectively.

Cumulative Effect of a Change in Accounting Principle

Results in 2005 included an after-tax charge of $9 million recorded upon the adoption of FIN 47 in December 2005. We identified applicable legal obligations as defined under FIN 47 at our active and retired generating units, identifying asbestos as the primary conditional ARO. We recorded a conditional ARO liability of $16 million (including accumulated accretion for the period from the date the liability was incurred to the date of adoption), an asset retirement cost of $4 million (recorded as part of the carrying amount of the related long-lived asset), and accumulated depreciation of $1 million. The remaining cumulative effect adjustment for unrecognized depreciation and accretion of $14 million was charged to income ($9 million, net of tax) for the year ended December 31, 2005 (see Note 8).

PJM AND MISO INTERCONNECTION TRANSACTIONS

We engage in purchase and sale transactions in the PJM market to support the supply of end-use customers, including PLR requirements in Pennsylvania. In conjunction with FirstEnergy’s dedication of the Beaver Valley Plant to PJM on January 1, 2005, we began accounting for purchase and sale transactions in the PJM market based on our net hourly position - recording each hour as either an energy purchase or an energy sale in the Consolidated Statements of Income. Hourly energy positions are aggregated to recognize gross purchases and sales for the month. This revised method of accounting, which has no impact on net income, is consistent with the practice of other energy companies that have dedicated generating capacity in PJM and correlates with PJM's scheduling and reporting of hourly energy transactions. We also apply the net hourly methodology to purchase and sale transactions in MISO's energy market, which became active on April 1, 2005.

CAPITAL RESOURCES AND LIQUIDITY

Our cash requirements in 2006 for operating expenses, construction expenditures and redemptions were met with a combination of cash from operations, unregulated money pool and funds from the capital markets. During 2007, we expect to meet our contractual obligations primarily with cash from operations, short-term credit arrangements and funds from the capital markets. In addition, the receipt of a $700 million equity contribution from FirstEnergy in February 2007 is further discussed under Cash Flows from Financing Activities. Borrowing capacity under the unregulated money pool is available to manage 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 $2,000 remain unchanged from December 31, 2005.

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Cash Flows From Operating Activities

Our net cash provided from operating activities in 2006, 2005 and 2004 is summarized as follows:

Operating Cash Flows	2006		2005			2004
	(In millions)
Net income	$	419	$	205		$	327
Non-cash charges		396		359			479
Pension trust contribution*		21		(9	)		(37	)
Working capital and other		23		92			(55	)
Net cash provided from operating activities	$	859	$	647		$	714

* Pension trust contributions in 2005 and 2004 are net of $4 million and $25 million of related current year cash income tax benefits, respectively. The $21 million cash inflow in 2006 represents reduced income taxes paid in 2006 relating to a January 2007 pension contribution.

Net cash provided from operating activities increased by $212 million in 2006 compared to 2005 primarily due to a $214 million increase in net income and a $37 million increase in non-cash charges (see Results of Operations) and a $30 million change in the after-tax pension trust contribution impacts in 2006 from 2005.

Net cash provided from operating activities decreased by $67 million in 2005 compared to 2004 primarily due to a $122 million decrease in net income and a $120 million decrease in non-cash charges (see Results of Operations) which were partially offset by a $28 million decrease in the after-tax impact of pension trust contributions and a $117 million increase in returned cash collateral in 2005 compared to 2004.

Cash Flows From Financing Activities

Cash provided from financing activities was $57 million and $148 million in 2006 and 2005, respectively, and $306 million of cash was used for financing activities in 2004. Except for $8 million of common stock dividends to FirstEnergy in 2006 and a $262 million equity contribution from FirstEnergy in 2005, these changes reflected new issues and debt redemptions shown below:

Securities Issued or Redeemed	2006		2005			2004
	(In millions)
New Issues
Pollution control notes	$	1,157	$	-		$	-
Redemptions
Long-term associated company notes payable	$	1,138	$	-		$	326
Short-term borrowings (repayments), net	$	46	$	(114	)	$	20

We had approximately $1 billion of short-term indebtedness as of December 31, 2006 and December 31, 2005.

On August 24, 2006, we, FirstEnergy and certain of its subsidiaries, entered into a new $2.75 billion five-year revolving credit facility, which replaced FirstEnergy’s prior $2 billion credit facility. 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. We are currently unable to borrow under the facility, but we will have the capacity to borrow up to $250 million when we are able to deliver notice to the administrative agent that either we have senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody’s or that FirstEnergy has guaranteed our obligations under the facility.

The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of December 31, 2006, our debt to total capitalization ratio as defined under the revolving credit facility was 69%. After giving effect to a $700 million equity contribution from FirstEnergy in February 2007 and the concurrent reduction of $617 million of long-term notes, the debt to total capital ratio would have been 58% as of December 31, 2006.

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On March 2, 2007, FES entered into a $250 million bridge loan facility with Morgan Stanley Senior Funding, Inc. FirstEnergy will provide a guaranty of FES' bridge loan obligations until such time as FES provides the lender with notice that its senior unsecured debt is rated at least BBB- by S&P or Baa3 by Moody's. On March 26, 2007, S&P assigned FES a corporate credit rating of BBB. On March 27, 2007, Moody's assigned FES an issuer rating of Baa2.

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

We have the ability to borrow from FirstEnergy to meet our short-term working capital requirements. FESC administers a money pool and tracks surplus funds of FirstEnergy and its unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, 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 approximately 5.22%.

On November 16, 2006, $26 million of pollution control revenue bonds were issued by the Pennsylvania Economic Development Financing Authority on behalf of FGCO to finance a portion of the costs of solid waste disposal facilities at FGCO’s Bruce Mansfield Plant. This refunding is currently supported by a bank LOC for which FirstEnergy is the guarantor of the reimbursement obligations of FGCO. A $43 million financing through the same Pennsylvania authority was completed in December 2005 for this project, also supported by a bank LOC and FirstEnergy guaranty.

On April 3, 2006, $253 million of pollution control revenue refunding bonds were issued by Ohio and Pennsylvania industrial development authorities on behalf of NGC ($106 million) and FGCO ($147 million). On December 5, 2006, $878 million of pollution control revenue refunding bonds were issued by such authorities on behalf of NGC ($485 million) and FGCO ($393 million). In each case, proceeds from the issuance and sale of the bonds were used to refund an equal aggregate amount of pollution control bonds previously issued in various series on behalf of OE, Penn, CEI and TE. The refundings resulted in corresponding reductions in each of the utility operating subsidiaries’ notes receivable from NGC and FGCO relating to the GAT. All of the refunding issues are currently supported by bank LOCs for which FirstEnergy is either the account party or the guarantor of the reimbursement obligation of NGC or FGCO, as applicable. Provisions have been included in the April 2006 transactions and the November 2006 transaction described in the prior paragraph, that permit us to replace FirstEnergy as guarantor effective as early as 91 days after we obtain senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody’s. Similar provisions are contained in NGC’s $270 million of pollution control debt issued in 2005, but not the FGCO December 2005 transaction described above.

Cash Flows From Investing Activities

Net cash flows used in investing activities resulted primarily from property additions which are principally generation-related.

Net cash used for investing activities in 2006 increased by $121 million compared to 2005. The increase was principally due to a $166 million increase in property additions which reflects the replacement of the steam generators and reactor head at Beaver Valley Unit 1 and air quality control system expenditures, and a $41 million increase in loans to associated companies. These increases were partially offset by an $89 million decrease in contributions to nuclear decommissioning trusts due to the completion of the Ohio Companies' and Penn's decommissioning funding schedules assumed in the GAT.

Net cash used for investing activities in 2005 increased by $386 million from 2004. The increase was principally due to a $292 million increase in loans to associated companies and a $99 million increase in property additions.

Our capital spending for the period 2007-2011 is expected to be about $2.8 billion (excluding nuclear fuel), of which $571 million applies to 2007. Investments for additional nuclear fuel during the 2007-2011 period are estimated to be approximately $893 million, of which about $86 million applies to 2007. During the same period, our nuclear fuel investments are expected to be reduced by approximately $702 million and $103 million, respectively, as the nuclear fuel is consumed.

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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	$	3,084	$	-	$	-	$	-	$	3,084
Interest on long-term debt (1)		1,384		51		107		107		1,119
Short-term borrowings		1,022		1,022
Pension funding (2)		64		64		-		-		-
Fuel and purchased power (3)		6,432		1,074		1,737		1,570		2,051
Total	$	11,986	$	2,211	$	1,844	$	1,677	$	6,254

(1)   Reflects applicable variable interest rates at December 31, 2006. See Consolidated Statements of

Capitalization.

(2)   We estimate that no further pension contributions will be required during the 2008-2011 period to maintain

our defined benefit pension plan's funding at a minimum required level as determined by government

regulations. We are unable to estimate projected contributions beyond 2011. See Note 3 to the consolidated

financial statements.

(3)   Amounts under contract with fixed or minimum quantities and approximate timing.

Guarantees and Other Assurances

In anticipation of the S&P and Moody’s credit ratings discussed above, we will enter into downstream guaranties in favor of present and future holders of FGCO and NGC indebtedness and FGCO and NGC will enter into upstream guaranties in favor of present and future holders of our indebtedness, which will provide guaranteed parties with claims against us and either of our subsidiaries, FGCO and NGC, regardless of whether their primary obligor is either us or either of our subsidiaries, FGCO or NGC. In addition, as previously disclosed, provisions have been included in FGCO and NGC 2005 and 2006 debt transaction documents that permit us to replace FirstEnergy as guarantor effective as early as 91 days after we attain senior debt ratings of at least BBB- by S&P and Baa3 by Moody’s.

OFF-BALANCE SHEET ARRANGEMENTS

We do not have any equity ownership interests in businesses that are accounted for under the equity method.

MARKET RISK INFORMATION

We use various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight to risk management activities.

Commodity Price Risk

We are exposed to financial and market risks resulting from the fluctuation of interest rates and commodity prices primarily due to fluctuations in electricity, energy transmission, natural gas, coal, nuclear fuel and emission allowance prices. To manage the volatility relating to these exposures, we use a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. Derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of our derivative hedging contracts qualify for the normal purchase and normal sale exception under SFAS 133 and are therefore excluded from the table below. The change in the fair value of commodity derivative contracts related to energy production during 2006 is summarized in the following table:

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Increase (Decrease) in the Fair Value of Derivative Contracts	Non-Hedge			Hedge			Total
	(In millions)
Change in the fair value of commodity derivative contracts:
Outstanding net liability as of January 1, 2006	$	(1	)	$	(3	)	$	(4	)
Additions/change in value of existing contracts		(10	)		(23	)		(33	)
Settled contracts		8			9			17
Other		-			-			-
Outstanding net liability as of December 31, 2006	$	(3	)	$	(17	)	$	(20	)
Non-commodity net liabilities as of December 31, 2006:
Interest rate swaps	$	-		$	(39	)	$	(39	)
Net liabilities - derivative contacts as of December 31, 2006	$	(3	)	$	(56	)	$	(59	)
Impact of changes in commodity derivative contracts(*)
Income Statement effects (Pre-Tax)	$	4		$	-		$	4
Balance Sheet effects:
OCI (Pre-Tax)	$	-		$	(14	)	$	(14	)

^(*)   Represents the change in value of existing contracts, settled contracts and changes in techniques/ assumptions.

Derivatives are included on the Consolidated Balance Sheet as of December 31, 2006 as follows:

Balance Sheet Classification	Non-Hedge			Hedge			Total
	(In millions)
Current-
Other assets	$	-		$	21		$	21
Other liabilities		(4	)		(38	)		(42	)
Non-Current-
Other deferred charges		-			16			16
Other noncurrent liabilities		-			(55	)		(55	)
Net liabilities	$	(4	)	$	(56	)	$	(60	)

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, we rely on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. We use these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts by year are summarized in the following table:

Source of Information
- Fair Value by Contract Year	2007			2008		2009		2010		2011		Thereafter		Total
	(In millions)
Prices actively quoted(1)	$	(3	)	$	-	$	-	$	-	$	-	$	-	$	(3	)
Other external sources(2)		(17	)		-		-		-		-		-		(17	)
Prices based on models		-			-		-		-		-		-		-
Total	$	(20	)	$	-	$	-	$	-	$	-	$	-	$	(20	)

⁽¹⁾Exchange traded.

⁽²⁾Broker quote sheets.

We perform sensitivity analyses to estimate our exposure to the market risk of our commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on our derivative instruments would not have had a material effect on our consolidated financial position (assets, liabilities and equity) or cash flows as of December 31, 2006. Based on derivative contracts held as of December 31, 2006, an adverse 10% change in commodity prices would decrease net income by approximately $2 million for the next 12 months.

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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 table below.

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								$	424		$	424		$	428
Average interest rate									4.2	%		4.2	%
Liabilities
Long-term Debt and Other
Long-term Obligations:
Fixed rate								$	1,599		$	1,599		$	1,599
Average interest rate									4.8	%		4.8	%
Variable rate								$	1,485		$	1,485		$	1,485
Average interest rate									3.9	%		3.9	%
Short-term Borrowings	$	1,022									$	1,022		$	1,022
Average interest rate		5.6	%									5.6	%

We are subject to the inherent interest rate risks related to refinancing maturing debt by issuing new debt securities. Fluctuations in the fair value of NGC's decommissioning trust balances will eventually affect earnings (immediately for unrealized losses and affecting OCI initially for unrealized gains) based on the guidance in SFAS 115 and FSP SFAS 115-1 and SFAS 124-1. As of December 31, 2006, NGC’s decommissioning trust balance totaled $1.2 billion. As of December 31, 2006, the trust balance was comprised of 70% equity securities and 30% debt instruments.

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $872 million as of December 31, 2006. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $87 million reduction in fair value as of December 31, 2006 (see Note 4 - Fair Value of Financial Instruments).

CREDIT RISK

Credit risk is the risk of an obligor’s failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. We engage in transactions for the purchase and sale of commodities including gas, electricity, coal and emission allowances. These transactions are often with major energy companies within the industry.

We maintain credit policies with respect to our counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of our credit program, we aggressively manage the quality of our portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As of December 31, 2006, the largest credit concentration with one non-affiliated party (currently rated investment grade) represented 10.7% of our total credit risk. As of December 31, 2006, 99%of our credit exposure, net of collateral and reserves, was with non-affiliated investment-grade counterparties.

POWER SUPPLY AGREEMENTS WITH REGULATED AFFILIATES

Met-Ed and Penelec have been purchasing a portion of their PLR requirements from us through a partial requirements wholesale power sales agreement and various amendments. Under these agreements, we retained the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec. Our agreements have reduced Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR capacity and energy costs during the term of these agreements with us.

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On April 7, 2006, the parties entered into a tolling agreement that arose from our notice to Met-Ed and Penelec that we elected to exercise our right to terminate the partial requirements agreement effective midnight December 31, 2006. On November 29, 2006, Met-Ed, Penelec and we agreed to suspend the April 7 tolling agreement pending resolution of the PPUC’s proceedings regarding the Met-Ed and Penelec Transition Rate Plan cases filed April 10, 2006. Separately, on September 26, 2006, Met-Ed and Penelec successfully conducted a competitive RFP for a portion of their PLR obligations for the period December 1, 2006 through December 31, 2008. We were one of the successful bidders in that RFP process and on September 26, 2006, entered into a supplier master agreement to supply a certain portion of Met-Ed’s and Penelec’s PLR requirements at market prices that substantially exceed the fixed price in the partial requirements agreements.

Based on the outcome of the Transition Rate Plan filing, Met-Ed, Penelec and we agreed to restate the partial requirements power sales agreement effective January 1, 2007. The restated agreement incorporates the same fixed price for residual capacity and energy supplied by us as in the prior arrangements between the parties and automatically extends for successive one-year terms unless any party gives 60 days’ notice prior to the end of the year. The restated agreement also allows Met-Ed and Penelec to sell the output of their NUG generation to the market and requires us to provide energy at fixed prices to replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec to satisfy their PLR obligations. The parties also have separately terminated the tolling, suspension and supplier master agreements in connection with the restatement of the partial requirements agreement. Accordingly, the energy that would have been supplied under the supplier master agreement will now be provided under the restated partial requirements agreement.

On November 18, 2004, the FERC issued an order eliminating the RTOR for transmission service between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a SECA mechanism to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and we participated in the FERC hearings held in May 2006 concerning the calculation and imposition of the SECA charges. The Presiding Judge issued an Initial Decision on August 10, 2006, rejecting the compliance filings made by the RTOs and transmission owners, ruling on various issues and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the Initial Decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC in early 2007.

On November 1, 2005, we filed two PSAs for approval with the FERC. One PSA required us 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 us if the Ohio CBP results in a lower price for retail customers. A similar PSA between us and Penn permits Penn to obtain its PLR power requirements from us at a fixed price equal to the retail generation price during 2006.

On December 29, 2005, the FERC issued an order setting the two PSAs for hearing. The order criticized the Ohio CBP, and required us 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 us 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. We, 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 PSAs with us. Under the Ohio PSA, 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 us no more than the lower of (i) the sum of the retail generation charge, the rate stabilization charge, the fuel recovery mechanism charge, and our 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 us to provide this power. We billed the Ohio Companies for the additional amount payable to us for incremental fuel costs on power supplied during 2006. The total power supply cost billed by us 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 us under the Penn PSA can be no greater than the generation component of charges for retail PLR load in Pennsylvania. The modifications to the Ohio and Pennsylvania PSAs became effective January 1, 2006. The Penn PSA subject to the settlement expired at midnight on December 31, 2006.

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As a result of Penn’s PLR competitive solicitation process approved by the PPUC for the period January 1, 2007 through May 31, 2008, we were 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, we 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.

FERC MATTERS

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 our facilities are located within the ReliabilityFirst region and, as a result, ReliabilityFirst is charged with administering the reliability standards as such standards apply to our facilities. We believe we are in compliance with all current NERC reliability standards.

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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 13 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.

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 by our regulated affiliates. If we are unable to meet the reliability standards discussed above for our facilities in the future, we would be required to move into compliance, which could have a material adverse effect on us and our subsidiaries’ financial condition, results of operations and cash flows. In addition, failure to comply with the reliability standards approved by the FERC can result in the imposition of fines and civil penalties.

On March 16, 2007, the FERC issued a final rule approving the 83 mandatory reliability standards. The final rule will take effect on June 4, 2007. The FERC also directed NERC to improve 56 reliability standards. The final rule has not yet been fully evaluated to assess its impact on our operations.

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 established March 30, 2007, as the date for interested parties to submit comments addressing the filing. FESC filed comments on behalf of FES on March 30, 2007. Although there are certain features of the proposal that will need to be refined and/or more fully developed before the Ancillary Services Market will be fully operational, FirstEnergy supports MISO’s proposal to establish a competitive Ancillary Services Market.

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 become effective on May 14, 2007. The final rule has not yet been fully evaluated to assess its impact on FirstEnergy’s operations.

ENVIRONMENTAL MATTERS

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

Clean Air Act Compliance

We are required to meet federally approved SO₂ emissions regulations. Violations of such regulations can result in shutdown of a generating unit involved and/or civil or criminal penalties of up to $32,500 for each day a unit is in violation. The EPA has an interim enforcement policy for SO₂ regulations in Ohio that allows for compliance based on a 30-day averaging period. We believe that we are currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the Clean Air Act. We have disputed those alleged violations based on its Clean Air Act permit, the Ohio SIP and other information provided at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. At the time of the alleged violation, our affiliate, TE, owned the Bay Shore Power Plant, which we now own and operate.

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We comply with SO₂ reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NO_X reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NO_X reductions at our facilities. The EPA's NO_X Transport Rule imposes uniform reductions of NO_X emissions (an approximate 85% reduction in utility plant NO_X emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NO_X emissions are contributing significantly to ozone levels in the eastern United States. We believe our facilities also are complying with the NO_X budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and fine particulate matter. In March 2005, the EPA finalized CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR provided each affected state until 2006 to develop implementing regulations to achieve additional reductions of NO_X and SO₂ emissions in two phases (Phase I in 2009 for NO_X, 2010 for SO₂ and Phase II in 2015 for both NO_X and SO₂). Our Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to caps on SO₂ and NO_X emissions, whereas its New Jersey fossil-fired generation facility will be subject to a cap on NO_X emissions only. According to the EPA, SO₂ emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO₂ emissions in affected states to just 2.5 million tons annually. NO_X emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NO_X cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which we operate affected facilities.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides for a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, mercury emissions will be capped nationally at 38 tons by 2010 (as a "co-benefit" from implementation of SO₂ and NO_X emission caps under the EPA's CAIR program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the CAMR have been challenged in the United States Court of Appeals for the District of Columbia. Our future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which we operate affected facilities.

The model rules for both the CAIR and the CAMR contemplate an input-based methodology to allocate allowances to affected facilities. Under this approach, allowances would be allocated based on the amount of fuel consumed by the affected sources. We would prefer an output-based generation-neutral methodology in which allowances are allocated based on megawatts of power produced, allowing new and non-emitting generating facilities (including renewables and nuclear) to be entitled to their proportionate share of the allowances. Consequently, we will be disadvantaged if these model rules were implemented as proposed because our substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.

Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap and trade approach as in the CAMR, but rather follows a command and control approach imposing emission limits on individual sources. Pennsylvania’s mercury regulation would deprive us of mercury emission allowances that were to be allocated to the Mansfield Plant under the CAMR and that would otherwise be available for achieving our system-wide compliance. The future cost of compliance with these regulations, if approved and implemented, may be substantial.

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, and is now owned by FGCO. 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.

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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 of our 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 FirstEnergy fails 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, FGCO and its affiliates, OE and Penn, 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 FGCO and its affiliates, OE and Penn, 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.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity - the ratio of emissions to economic output - by 18% through 2012. The EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

We cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO₂ emissions could require significant capital and other expenditures. However, the CO₂ emissions per kilowatt-hour of electricity generated by us is lower than many regional competitors due to our diversified generation sources which include low or non-CO₂ emitting gas-fired and nuclear generators.

On April 2, 2007, the United States Supreme Court found that EPA has the authority to regulate CO₂ emissions from automobiles as “air pollutants” under the Clear Air Act. Although this decision did not address CO₂ emissions from electric generating plants, EPA has similar authority under the Clan Air Act to regulate “air pollutants” from those and other facilities. FirstEnergy cannot estimate the financial impact of possible EPA regulation of CO₂ emissions, although potential restrictions on CO₂ emissions could require significant capital and other expenditures.

Regulation of Hazardous Waste

Under NRC regulations, we and our affiliates, OE and TE, must ensure that adequate funds will be available to decommission our nuclear facilities in proportion to our respective ownership or leased interests in the nuclear units. As of December 31, 2006, approximately $1.4 billion (NGC - $1.2 billion and other affiliates - $0.2 billion) was invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley and Perry. As part of the application to the NRC to transfer the ownership of these nuclear facilities to NGC, FirstEnergy agreed to contribute another $80 million to these trusts by 2010; $63 million of which has been recognized as a notes receivable on the Consolidated Balance Sheet. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy plans to seek for these facilities.

See Note 10(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

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OTHER LEGAL PROCEEDINGS

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

Nuclear Plant Matters

On January 20, 2006, FENOC announced that it had entered into a deferred prosecution agreement with the U.S. Attorney’s Office for the Northern District of Ohio and the Environmental Crimes Section of the Environment and Natural Resources Division of the DOJ related to FENOC’s communications with the NRC during the fall of 2001 in connection with the reactor head issue at the Davis-Besse Nuclear Power Station. Under the agreement, the United States acknowledged FENOC’s extensive corrective actions at Davis-Besse, FENOC’s cooperation during investigations by the DOJ and the NRC, FENOC’s pledge of continued cooperation in any related criminal and administrative investigations and proceedings, FENOC’s acknowledgement of responsibility for the behavior of its employees, and its agreement to pay a monetary penalty. The DOJ agreed to refrain from seeking an indictment or otherwise initiating criminal prosecution of FENOC for all conduct related to the statement of facts attached to the deferred prosecution agreement, as long as FENOC remained in compliance with the agreement, which FENOC has done. A monetary penalty of $28 million (not deductible for income tax purposes) was reflected in NGC’s fourth quarter of 2005 results. The deferred prosecution agreement expired on December 31, 2006.

On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee's failure to take prompt and corrective action. On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Nuclear Power Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.

On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance at the Perry Nuclear Power Plant and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. In the NRC's 2005 annual assessment letter dated March 2, 2006 and associated meetings to discuss the performance of the Perry Nuclear Power Plant on March 14, 2006, the NRC again stated that the Perry Nuclear Power Plant continued to operate in a manner that "preserved public health and safety." However, the NRC also stated that increased levels of regulatory oversight would continue until sustained improvement in the performance of the facility was realized.

By two letters dated March 2, 2007, the NRC closed the Confirmatory Action Letter commitments for Perry, the two outstanding white findings, and crosscutting issues. Moreover, the NRC removed Perry from the Multiple Degraded Cornerstone Column of the NRC Action Matrix and placed the plant in the Licensee Response Column (regular agency oversight).

If it were ultimately determined that we or our 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 our financial condition, results of operations and cash flows.

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.

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.

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Pension and Other Postretirement Benefits Accounting

Pension and postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. 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.

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 also are 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 was $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 qualified pension 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 $64 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 continue to increase 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 our health care plans, and projections of future medical trend rates. The effect on our portion of the 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%		$	1.1	$	0.2	$	1.3
Long-term return on assets		Decrease by 0.25%		$	0.9	$	0.1	$	1.0
Health care trend rate		Increase by 1%			na	$	0.5	$	0.5

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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.

Income Taxes

We record 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 recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled.

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. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. 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 our 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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FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2006			2005			2004
	(In thousands)
REVENUES:
Electric sales to affiliates (Note 2(I))	$	2,609,299		$	2,425,251		$	2,634,594
Other		1,402,054			1,541,988			2,571,567
Total revenues		4,011,353			3,967,239			5,206,161
EXPENSES (Note 2(I)):
Fuel		1,105,657			1,005,877			718,891
Purchased power from non-affiliates		590,491			957,570			2,276,591
Purchased power from affiliates		257,001			308,602			326,241
Other operating expenses		1,027,564			980,182			954,469
Provision for depreciation		179,163			177,231			198,503
General taxes		73,332			67,302			66,350
Total expenses		3,233,208			3,496,764			4,541,045
OPERATING INCOME		778,145			470,475			665,116
OTHER INCOME (EXPENSE):
Investment income		45,937			78,787			61,175
Miscellaneous income (expense)		8,565			(34,143	)		(9,771	)
Interest expense to affiliates (Note 2(I))		(162,673	)		(184,317	)		(171,007	)
Interest expense - other		(26,468	)		(12,038	)		(10,613	)
Capitalized interest		11,495			14,295			16,914
Total other expense		(123,144	)		(137,416	)		(113,302	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		655,001			333,059			551,814
INCOME TAXES		236,348			124,499			229,575
INCOME FROM CONTINUING OPERATIONS		418,653			208,560			322,239
Discontinued operations (net of income taxes of $3,761,000
and $3,038,000, respectively) (Note 2(G))		-			5,410			4,396
INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE
IN ACCOUNTING PRINCIPLE		418,653			213,970			326,635
Cumulative effect of a change in accounting principle (net of income
tax benefit of $5,507,000) (Note 2(H))		-			(8,803	)		-
NET INCOME	$	418,653		$	205,167		$	326,635
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

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FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED BALANCE SHEETS
As of December 31,	2006		2005
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2	$	2
Receivables-
Customers (less accumulated provisions of $9,907,000 and $11,532,000,		129,843		99,315
respectively, for uncollectible accounts)
Associated companies		235,532		236,651
Other (less accumulated provisions of $5,593,000 and $5,599,000,
respectively, for uncollectible accounts)		4,085		14,880
Notes receivable from associated companies		752,919		291,626
Materials and supplies, at average cost		460,239		416,968
Prepayments and other		57,546		48,881
		1,640,166		1,108,323
PROPERTY, PLANT AND EQUIPMENT:
In service		8,355,344		7,704,424
Less - Accumulated provision for depreciation		3,818,268		3,685,328
		4,537,076		4,019,096
Construction work in progress		339,886		512,467
		4,876,962		4,531,563
INVESTMENTS:
Nuclear plant decommissioning trusts		1,238,272		1,094,176
Long-term notes receivable from associated companies		62,900		62,900
Other		72,509		79,477
		1,373,681		1,236,553
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		24,248		24,248
Property taxes		44,111		42,076
Prepaid pension costs (Note 3)		-		49,115
Accumulated deferred income taxes		-		16,464
Other		39,839		92,148
		108,198		224,051
	$	7,999,007	$	7,100,490
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,469,660	$	312,750
Notes payable to associated companies		1,022,197		975,795
Accounts payable-
Associated companies		556,049		469,621
Other		136,631		192,480
Accrued taxes		113,231		103,788
Other		100,941		76,000
		3,398,709		2,130,434
CAPITALIZATION:
Common stockholder's equity		1,859,363		1,401,334
Long-term debt		1,614,222		2,615,247
		3,473,585		4,016,581
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		121,449		-
Accumulated deferred investment tax credits		65,751		70,409
Asset retirement obligations		760,228		716,169
Retirement benefits		103,027		118,092
Property taxes		44,433		43,625
Other		31,825		5,180
		1,126,713		953,475
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	7,999,007	$	7,100,490
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.

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FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31,		2006			2005
		(Dollars in thousands)
COMMON STOCKHOLDER'S EQUITY:
Common stock, without par value, authorized 750 shares - 8 shares outstanding	$	1,050,302		$	1,048,734
Accumulated other comprehensive income (Note 2(F))		111,723			65,461
Retained earnings (Note 7(A))		697,338			287,139
Total common stockholder's equity		1,859,363			1,401,334
LONG-TERM DEBT (Note 7(B)):
Secured notes:
FE Generation Corp.
3.980% due to associated companies 2025 (Note 1)		770,912			1,021,522
4.380% due to associated companies 2025 (Note 1)		35,952			100,972
5.390% due to associated companies 2025 (Note 1)		13,967			74,467
5.990% due to associated companies 2025 (Note 1)		221,485			383,131
		1,042,316			1,580,092
FE Nuclear Generation Corp.
4.380% due to associated companies 2025 (Note 1)		55,100			166,331
5.990% due to associated companies 2025 (Note 1)		265,150			478,350
		320,250			644,681
Total secured notes		1,362,566			2,224,773
Unsecured notes:
FE Generation Corp.
*  3.910% due 2017		28,525			-
*  4.000% due 2019		90,140			-
*  3.950% due 2023		234,520			-
*  4.350% due 2028		15,000			15,000
*  4.050% due 2040		43,000			43,000
*  3.940% due 2041		129,610			-
*  3.980% due 2041		56,600			-
*  4.050% due 2041		26,000			-
		623,395			58,000
FE Nuclear Generation Corp.
*  3.870% due 2033		15,500			-
*  3.870% due 2033		135,550			-
*  3.920% due 2033		62,500			-
*  3.930% due 2033		99,100			99,100
*  3.930% due 2033		8,000			8,000
*  3.950% due 2033		107,500			-
*  3.990% due 2033		46,500			-
*  3.940% due 2034		82,800			82,800
*  3.950% due 2034		7,200			7,200
*  3.870% due 2035		163,965			-
*  3.950% due 2035		72,650			72,650
*  3.970% due 2035		60,000			-
3.980% due to associated companies 2025 (Note 1)		56,000			194,821
5.390% due to associated companies 2025 (Note 1)		180,720			180,720
		1,097,985			645,291
Total unsecured notes		1,721,380			703,291
Net unamortized discount on debt		(64	)		(67	)
Long-term debt due within one year		(1,469,660	)		(312,750	)
Total long-term debt		1,614,222			2,615,247
TOTAL CAPITALIZATION	$	3,473,585		$	4,016,581
* 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.

25

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
								Accumulated			Retained
								Other			Earnings
	Comprehensive			Number		Carrying		Comprehensive			(Accumulated
	Income			of Shares		Value		Income			Deficit)
	(Dollars in thousands)
Balance, January 1, 2004				8		$ 783,685		$ 61,782			$ (245,504		)
Net income	$	326,635										326,635
Net unrealized loss on derivative instruments, net
of $3,903,000 of income tax benefits		(5,561	)						(5,561	)
Unrealized gain on investments, net of
$11,896,000 of income taxes		16,270							16,270
Minimum liability for unfunded retirement
benefits, net of $660,000 of income taxes		12,027							12,027
Comprehensive income	$	349,371
Balance, December 31, 2004					8		783,685		84,518			81,131
Net income	$	205,167										205,167
Net unrealized loss on derivative instruments, net
of $2,414,000 of income tax benefits		(3,595	)						(3,595	)
Unrealized loss on investments, net of
$9,658,000 of income tax benefits		(15,462	)						(15,462	)
Comprehensive income	$	186,110
Equity contribution from parent							262,200
Stock options exercised, restricted stock units
and other adjustments							2,849					841
Balance, December 31, 2005					8		1,048,734		65,461			287,139
Net income	$	418,653										418,653
Net unrealized loss on derivative instruments, net
of $5,082,000 of income tax benefits		(8,248	)						(8,248	)
Unrealized gain on investments, net of
$33,698,000 of income taxes		58,654							58,654
Comprehensive income	$	469,059
Net liability for unfunded retirement benefits
due to the implementation of SFAS 158, net
of $10,825,000 of income tax benefits									(4,144	)
Stock options exercised, restricted stock units
and other adjustments							1,568
Cash dividends declared on common stock												(8,454	)
Balance, December 31, 2006					8	$	1,050,302	$	111,723		$	697,338
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

26

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,	2006			2005			2004
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:	$	418,653		$	205,167		$	326,635
Net Income
Adjustments to reconcile net income to net cash from
operating activities-
Provision for depreciation		179,163			177,231			198,503
Nuclear fuel amortization		89,178			86,748			88,068
Deferred income taxes and investment tax credits, net		115,878			94,602			155,417
Cumulative effect of a change in accounting principle		-			8,803			-
Accrued compensation and retirement benefits		25,052			27,960			35,699
Commodity derivative transactions, net		24,144			(219	)		11,353
Gain on asset sales		(37,663	)		(30,239	)		(5,097	)
Income from discontinued operations (Note 2(G))		-			(5,410	)		(4,396	)
Cash collateral, net		40,680			50,695			(66,384	)
Pension trust contribution		-			(13,291	)		(61,502	)
Decrease (increase) in operating assets-
Receivables		(15,462	)		(17,076	)		192,438
Materials and supplies		(1,637	)		(17,563	)		(3,708	)
Prepayments and other current assets		(5,237	)		(6,041	)		2,202
Increase (decrease) in operating liabilities-
Accounts payable		19,970			44,792			(221,772	)
Accrued taxes		12,235			35,252			54,444
Accrued interest		4,101			500			-
Other		(10,214	)		5,437			12,269
Net cash provided from operating activities		858,841			647,348			714,169
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		1,156,841			-			-
Short-term borrowings, net		46,402			-			19,739
Equity contribution from parent		-			262,200			-
Redemptions and Repayments-
Long-term debt		(1,137,740	)		-			(325,332	)
Short-term borrowings, net		-			(114,339	)		-
Common stock dividend payments		(8,454	)		-			-
Net cash provided from (used for) financing activities		57,049			147,861			(305,593	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(577,287	)		(411,560	)		(312,770	)
Proceeds from asset sales		34,215			58,087			8,723
Proceeds from nuclear decommissioning trust fund sales		1,054,216			1,286,319			919,691
Investments in nuclear decommissioning trust funds		(1,054,216	)		(1,375,424	)		(1,008,796	)
Loans to associated companies		(333,030	)		(291,626	)		-
Other		(39,788	)		(61,033	)		(15,651	)
Net cash used for investing activities		(915,890	)		(795,237	)		(408,803	)
Net change in cash and cash equivalents		-			(28	)		(227	)
Cash and cash equivalents at beginning of year		2			30			257
Cash and cash equivalents at end of year	$	2		$	2		$	30
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	173,337		$	195,519		$	177,213
Income taxes	$	155,771		$	20,274		$	63,930
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 FES (Company) and its wholly owned subsidiaries, FGCO and NGC. The Company is a wholly owned subsidiary of FirstEnergy. FirstEnergy also holds directly, or indirectly, all of the issued and outstanding common shares of its eight principal electric utility operating subsidiaries: OE, Penn, CEI, TE, ATSI, JCP&L, Met-Ed and Penelec. Penn is a wholly owned subsidiary of OE.

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 (GAT) 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 leasehold interests of CEI, TE and OE in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates. The GAT was accounted for as a transfer of assets under common control.

On October 24, 2005, the Ohio Companies and Penn 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, the Ohio Companies and Penn completed the intra-system transfer of their respective ownership in the nuclear generation assets to NGC through, in the case of OE and Penn, an asset spin-off by way of dividend and, in the case of CEI and TE, a sale at net book value. FENOC continues to operate and maintain the nuclear generation assets.

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.

Prior to completion of the GAT in the fourth quarter of 2005, the Company, through its subsidiary, FGCO, operated FirstEnergy’s non-nuclear generation businesses. Its pre-GAT historical results reflected the related non-nuclear generation fuel and operating costs as well as certain transactions and relationships with its affiliates. These included PSAs to provide electricity to the Ohio Companies and Penn to meet their PLR obligations, lease arrangements for their non-nuclear generation assets and purchased power agreements for their nuclear generation. The Ohio Companies and Penn reflected the nuclear fuel and operating costs and depreciation and property tax expenses related to their nuclear and non-nuclear generation assets in their pre-GAT historical results.

The consolidated financial statements of the Company and its subsidiaries as of December 31, 2006 and 2005 and for the years ended December 31, 2006, 2005 and 2004 represent the financial position, results of operations and cash flows as if the GAT had occurred as of December 31, 2003. Certain financial results, net assets and net cash flows related to the ownership of OE, Penn, CEI and TE of the transferred generation assets prior to the GAT are reflected in these consolidated financial statements. The revisions in certain affiliated company transactions and relationships that had existed prior to the GAT, which are discussed above, have been reflected for the three years ended December 31, 2006, 2005 and 2004 as if the GAT had been effective as of December 31, 2003. Those changes in the Company’s historical results and cash flows that began in the fourth quarter of 2005 have been estimated on an annualized basis and assumed to have begun at the end of 2003 and are reflected in the 2004 and 2005 financial statements. The Company’s results in 2006 reflect a full year of the GAT changes and therefore, no allocations or adjustments, except for those related to the NGC corporate restructuring discussed below, were reflected in the 2006 financial statements.

On December 28, 2006, the NRC approved the transfer of ownership in NGC from FirstEnergy to the Company. Effective December 31, 2006, NGC is a wholly owned subsidiary of the Company and a second tier subsidiary of FirstEnergy. FENOC continues to operate and maintain the nuclear generation assets. The consolidated financial statements assume that this corporate restructuring occurred at the end of 2003, with the Company’s and NGC’s financial position and results combined at the end of 2003 and associated company transactions and balances eliminated in consolidation.

Information in these consolidated financial statements was derived from historical and previously filed financial statements of FirstEnergy, OE, Penn, CEI and TE. Various allocation methodologies were employed to separate the results of operations and financial condition of the generation-related operations from the historical financial statements for the periods presented prior to the GAT. Certain assumptions used to reflect those various financial positions and transactions incorporated in the Company’s financial statements are described above.

28

Management believes that these assumptions and allocation methodologies are reasonable; however, had the GAT and FirstEnergy’s capital contribution of NGC to the Company actually occurred as of December 31, 2003, its results and financial position could have significantly differed from those presented herein. In addition, future results of operations, financial position and net cash flows could materially differ from the results presented in these consolidated financial statements.

The Company follows GAAP and complies with the regulations, orders, policies and practices prescribed by the SEC 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 disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period.

The Company operates in one business segment to generate and provide energy-related products and services to wholesale and retail customers in Ohio, Michigan, Pennsylvania, Maryland and New Jersey.

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)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.

(B) REVENUES AND RECEIVABLES-

The Company’s principal business is providing energy related products and services primarily in Ohio, Pennsylvania, Michigan, Maryland and New Jersey. This includes providing electric power to affiliated regulated utility companies through PSAs in order that the utility affiliates meet all or a portion of their PLR requirements. The Company’s retail customers are metered on a cycle basis. Electric revenues are recorded based on energy delivered through the end of the calendar month. An estimate of unbilled revenues is calculated to recognize electric service provided between the last meter reading date and the end of the month. This estimate includes many factors including historical customer usage, load profiles, estimated weather impacts, customer shopping activity and prices in effect for each class of customer. In each accounting period, the Company accrues the estimated unbilled amount receivable as revenue and reverses the related prior period estimate.

Receivables from customers include sales to residential, commercial and industrial customers and sales to non-affiliated wholesale customers. There was no material concentration of receivables as of December 31, 2006 with respect to any particular segment of the Company’s customers. Total customer receivables were $128 million (billed - $102 million and unbilled - $26 million) and $99 million (billed - $75 million and unbilled - $24 million) as of December 31, 2006 and 2005, respectively.

(C) ACCOUNTING FOR CERTAIN WHOLESALE ENERGY TRANSACTIONS-

The Company engages in purchase and sale transactions in the PJM Market to support the supply of end-use customers, including PLR requirements in Pennsylvania. In conjunction with FirstEnergy's dedication of the Beaver Valley Plant to PJM on January 1, 2005, the Company began accounting for purchase and sale transactions in the PJM Market based on its net hourly position -- recording each hour as either an energy purchase or an energy sale in the Consolidated Statements of Income. Hourly energy positions are aggregated to recognize gross purchases and sales for the month. This revised method of accounting, which has no impact on net income, is consistent with the practice of other energy companies that have dedicated generating capacity in PJM and correlates with PJM's scheduling and reporting of hourly energy transactions. The Company also applies the net hourly methodology to purchase and sale transactions in MISO's energy market, which became active on April 1, 2005 and continued through 2006.

For periods prior to January 1, 2005, FirstEnergy did not have substantial generating capacity in PJM and as such, the Company recognized purchases and sales in the PJM Market by recording each discrete transaction. Under those transactions, the Company would often buy a specific quantity of energy at a certain location in PJM and simultaneously sell a specific quantity of energy at a different location. Physical delivery occurred and the risks and rewards of ownership transferred with each transaction. The Company accounted for those transactions on a gross basis in accordance with EITF 99-19. The recognition of those transactions on a net basis in prior periods would have no impact on net income, but would have reduced both wholesale revenue and purchased power expense by $1.1 billion in 2004.

29

(D) PROPERTY, PLANT AND EQUIPMENT-

Property, plant and equipment reflects original cost for the nuclear generating assets (certain of which were adjusted to fair value in accordance with SFAS 144) and the purchase price of the non-nuclear generating assets (see Note 1 for further discussion), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs incurred prior to placing the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. The Company’s accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred.

The Company provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annual composite rate for the Company’s electric plant was approximately 3.5%, 3.7% and 4.1% in 2006, 2005 and 2004, respectively.

Jointly-Owned Generating Stations

The Company owns various power generating facilities, with OE, CEI and TE retaining interests in certain generating plants under sale and leaseback arrangements with non-affiliates that existed prior to the GAT (see Note 1 for further discussion). Each of the companies is obligated to pay a share of the costs associated with any jointly - owned facility in the same proportion as its interest. The Company’s portions of operating expenses associated with jointly - owned facilities are included in the corresponding operating expenses on the Consolidated Statements of Income. The amounts reflected on the Company’s Consolidated Balance Sheet under property, plant and equipment related to those jointly - owned facilities as of December 31, 2006 include the following:

	Utility	Accumulated	Construction	Company’s
	Plant	Provision for	Work in	Ownership
Generating Units	in Service	Depreciation	Progress	Interest
	(In millions)
Bruce Mansfield Units 1, 2 and 3	$ 1,393	$ 592	$ 12	67.89%
Beaver Valley Unit 2	137	23	18	60.08%
Perry	1,290	488	22	87.42%
Total	$ 2,820	$ 1,103	$ 52

Asset Retirement Obligations

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

Nuclear Fuel

Property, plant and equipment includes nuclear fuel recorded at original cost, which includes material, enrichment, fabrication and interest costs incurred prior to reactor load. Nuclear fuel is amortized based on the units of production method.

(E) ASSET IMPAIRMENTS-

Long-Lived Assets

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

30

Investments

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

(F)COMPREHENSIVE INCOME-

Comprehensive income includes net income as reported on the Consolidated Statements of Income and certain changes in common stockholder’s equity, except those resulting from transactions with FirstEnergy. As of December 31, 2006, AOCI consisted of unrealized gains on investments in securities available for sale of $126 million, a net liability for unfunded retirement benefits due to the implementation of SFAS 158, net of income tax benefits (see Note 3) of $4 million, and unrealized losses on derivative instrument hedges of $10 million. As of December 31, 2005, AOCI consisted of unrealized gains on investments in securities available for sale of $67 million and unrealized losses on derivative instrument hedges of $2 million.

(G)DIVESTITURES AND DISCONTINUED OPERATIONS-

In December 2004, the Company’s retail natural gas business qualified as assets held for sale in accordance with SFAS 144. As required by SFAS 142, goodwill associated with the natural gas business was tested for impairment as of December 31, 2004 with no impairment indicated. On March 31, 2005, the Company completed the sale of its retail natural gas business for an after-tax gain of $5 million.

Net results of $5 million (including the 2005 gain on the sale of assets discussed above) and $4 million associated with the divested retail gas business for 2005 and 2004, respectively, are reported as discontinued operations on the Consolidated Statements of Income. Pre-tax operating results were $1 million and $7 million in 2005 and 2004, respectively. Revenues associated with discontinued operations for 2005 and 2004 were $146 million and $496 million, respectively.

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

Results in 2005 included an after-tax charge of $9 million recorded upon the adoption of FIN 47 in December 2005. The Company identified applicable legal obligations as defined under FIN 47 at its active and retired generating units, identifying asbestos as the primary conditional ARO. The Company recorded a conditional ARO liability of $16 million (including accumulated accretion for the period from the date the liability was incurred to the date of adoption), an asset retirement cost of $4 million (recorded as part of the carrying amount of the related long-lived asset), and accumulated depreciation of $1 million. The remaining cumulative effect adjustment for unrecognized depreciation and accretion of $14 million was charged to income ($9 million, net of tax) for the year ended December 31, 2005 (see Note 8).

(I) TRANSACTIONS WITH AFFILIATED COMPANIES-

Operating revenues, operating expenses and interest expense include transactions with affiliated companies, primarily OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec and FESC. The Ohio transition plan resulted in the corporate separation of FirstEnergy's regulated and unregulated operations in 2001. The Company operates the former generation businesses of OE, Penn, CEI and TE. As a result, OE, Penn, CEI and TE entered into a PSA with the Company to meet their PLR obligations. OE, Penn, CEI and TE have completed the intra-system transfers of their generation assets to FGCO and NGC (see Note 1) excluding the leasehold interests of OE, CEI and TE in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliated entities. This resulted in the continuation of the sales arrangements with the Company for the generation KWH related to those leasehold interests. The Company has a partial requirements wholesale PSA with Met-Ed and Penelec (see Note 6). The Company is incurring interest expense through FGCO and NGC associated companies’ notes payable provided to OE, Penn, CEI and TE in exchange for the transferred assets. OE, CEI and TE continue to purchase their power from the Company to meet their PLR obligations. Penn’s PSA expired in December 2006 (see Note 6 for further discussion). The primary affiliated companies’ transactions are as follows:

31

	2006		2005		2004
	(In millions)
Revenues:
Electric sales to affiliates	$	2,609	$	2,425	$	2,635
Expenses:
Purchased power under PSA		243		275		278
Purchased power from JCP&L		14		33		48
FESC support services		64		48		54
Net Interest Charges:
Interest expense to affiliated utilities		109		129		145
Interest expense to FirstEnergy		53		55		26

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

32

(J)   INCOME TAXES-

For the Years Ended December 31,	2006			2005			2004
	(In thousands)
GENERAL TAXES:
Real and personal property	$	48,773		$	44,266		$	48,085
Social security and unemployment		12,854			12,070			11,216
State gross receipts*		10,115			9,305			6,048
Other		1,590			1,661			1,001
Total general taxes	$	73,332		$	67,302		$	66,350
*Collected from customers and included in revenue in the Consolidated Statements of Income.
PROVISION FOR INCOME TAXES:
Currently payable-
Federal	$	102,633		$	28,788			57,066
State		17,837			1,109			17,092
		120,470			29,897			74,158
Deferred, net-
Federal		110,052			94,071			123,291
State		10,484			5,223			36,851
		120,536			99,294			160,142
Investment tax credit amortization		(4,658	)		(4,692	)		(4,725	)
Total provision for income taxes	$	236,348		$	124,499		$	229,575
RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT
STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES:
Book income before provision for income taxes	$	655,001		$	333,059		$	551,814
Federal income tax expense at statutory rate	$	229,251		$	116,571		$	193,135
Increases (reductions) in taxes resulting from-
State income taxes, net of federal income tax benefit		18,409			4,116			35,063
Amortization of investment tax credits		(4,658	)		(4,692	)		(4,725	)
Penalties		-			9,800			-
Other, net		(6,654	)		(1,296	)		6,102
Total provision for income taxes	$	236,348		$	124,499		$	229,575
ACCUMULATED DEFERRED INCOME TAXES AS OF
DECEMBER 31:
Property basis differences	$	112,154		$	(736	)	$	142,256
Unamortized investment tax credits		(23,983	)		(25,676	)		(31,129	)
Other comprehensive income		60,173			42,382			54,454
Retirement benefits		(27,522	)		(42,529	)		(38,083	)
Asset retirement obligations		29,273			45,815			6,671
Allowance for doubtful accounts		(5,803	)		(7,142	)		(8,167	)
State operating loss carryforwards		(3,461	)		(2,740	)		(10,796	)
Investment impairment		(14,037	)		(14,035	)		(12,578	)
All other		(5,345	)		(11,803	)		(4,776	)
Net deferred income tax liability (asset)	$	121,449		$	(16,464	)	$	97,852

33

Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. The Company records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are ultimately settled. The Company is included in FirstEnergy's consolidated federal income tax return. The consolidated tax liability is allocated on a "stand-alone" company basis, with the Company recognizing any tax losses or credits it contributes to the consolidated return (See Note 5 for Ohio Tax Legislation discussion).

3.PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees. Pension and postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. The trusteed plans provide defined benefits based on years of service and compensation levels. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. FirstEnergy made a $300 million voluntary cash contribution to its qualified pension plan on January 2, 2007 (Company's share was $64 million). Projections indicate that additional cash contributions will not be required before 2016.

FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. The Company recognizes the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. During 2006, FirstEnergy amended the OPEB plan effective in 2008 to cap the monthly contribution for many of the retirees and their spouses receiving subsidized healthcare coverage. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement, for disability related benefits.

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

In December 31, 2006, FirstEnergy adopted SFAS 158. This Statement requires an employer to recognize an asset or liability for the overfunded or underfunded status of its 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. SFAS 158 required employers to recognize all unrecognized prior service costs and credits and unrecognized actuarial gains and losses in AOCI, net of income taxes. 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. The Company’s incremental impact of adopting SFAS 158 was a decrease of $33 million in pension assets, a decrease of $18 million in pension liabilities and a decrease in AOCI of $4 million, net of income taxes.

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

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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		568			325			69			33
Company contribution		-			500			54			58
Plan participants’ contribution		-			-			20			18
Benefits paid		(274	)		(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) at end of year		(43	)		1,023			(594	)		(1,057	)
Company’s share of net pension asset (liability) at end of year	$	(54	)	$	49		$	(43	)	$	(112	)
Amounts Recognized in
Accumulated Other Comprehensive Income
Prior service cost (credit)	$	63		$	-		$	(1,190	)	$	-
Actuarial (gain) loss		982			-			702			-
Net amount recognized	$	1,045		$	-		$	(488	)	$	-
Assumptions Used to Determine
Benefit Obligations As of December 31
Discount rate		6.00	%		5.75	%		6.00	%		5.75	%
Rate of compensation increase		3.50	%		3.50	%
Allocation of Plan Assets
As of December 31
Asset Category
Equity securities		64	%		63	%		72	%		71	%
Debt securities		29			33			26			27
Real estate		5			2			1			-
Private equities		1			-			-			-
Cash		1			2			1			2
Total		100	%		100	%		100	%		100	%

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

	Pension Benefits									Other Benefits
Components of Net Periodic Benefit Costs	2006			2005			2004			2006			2005			2004
	(In millions)
Service cost	$	83		$	77		$	77		$	34		$	40		$	36
Interest cost		266			254			252			105			111			112
Expected return on plan assets		(396	)		(345	)		(286	)		(46	)		(45	)		(44	)
Amortization of prior service cost		10			8			9			(76	)		(45	)		(40	)
Recognized net actuarial loss		58			36			39			56			40			39
Net periodic cost	$	21		$	30		$	91		$	73		$	101		$	103
Company’s share of net periodic cost	$	16		$	13		$	20		$	7		$	14		$	12
Weighted-Average Assumptions Used
to Determine Net Periodic Benefit Cost	Pension Benefits									Other Benefits
for Years Ended December 31		2006			2005			2004			2006			2005			2004
Discount rate		5.75	%		6.00	%		6.25	%		5.75	%		6.00	%		6.25	%
Expected long-term return on plan assets		9.00	%		9.00	%		9.00	%		9.00	%		9.00	%		9.00	%
Rate of compensation increase		3.50	%		3.50	%		3.50	%

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

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

Assumed Health Care Cost Trend Rates
As of December 31	2006			2005
Health care cost trend rate assumed for next
year (pre/post-Medicare)		9-11	%		9-11	%
Rate to which the cost trend rate is assumed to
decline (the ultimate trend rate)		5	%		5	%
Year that the rate reaches the ultimate trend
rate (pre/post-Medicare)		2011-2013			2010-2012

Assumed health care cost trend rates have a significant effect on the amounts reported for FirstEnergy’s health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	1-Percentage-		1-Percentage-
	Point Increase		Point Decrease
	(In millions)
Effect on total of service and interest cost	$	6	$	(5	)
Effect on accumulated postretirement benefit obligation	$	33	$	(29	)

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

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

4.FAIR VALUE OF FINANCIAL INSTRUMENTS

(A)LONG-TERM DEBT-

All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost in the caption "short-term borrowings", which approximates their fair market value. The following table provides the approximate fair value and related carrying amounts of long-term debt and long-term notes payable with affiliated companies 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	$	1,485	$	1,485	$	328	$	328
Long-term notes payable to affiliated companies		1,599		1,599		2,600		2,600
	$	3,084	$	3,084	$	2,928	$	2,928

The fair values of long-term debt and long-term notes payable with affiliated companies 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.

(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 the nuclear decommissioning trust fund investments as of December 31:

		2006				2005
		Carrying		Fair		Carrying		Fair
		Value		Value		Value		Value
		(In millions)
Restricted funds		$	8	$	8	$	-	$	-
Notes receivable			69		66		71		68
Debt securities:
	- Government obligations		58		58		71		71
		$	135	$	132	$	142	$	139

The table above includes restricted funds, notes receivable, and other miscellaneous investments. The carrying value of the restricted funds is assumed to approximate market value. The fair value of notes receivable represents the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms and have maturities ranging from 2007 to 2040. The other miscellaneous investments are primarily government obligations with fair values equal to cost.

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The following table provides the amortized cost basis, unrealized gains and losses, and fair values for the investments in debt and equity securities above excluding 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	$	58	$	-	$	-	$	58	$	71	$	-	$	-	$	71
	$	58	$	-	$	-	$	58	$	71	$	-	$	-	$	71

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

(C)NUCLEAR DECOMMISSIONING TRUST FUND INVESTMENTS-

Nuclear decommissioning trust investments are classified as available-for-sale with the fair value representing quoted market prices. The Company has no securities held for trading purposes. Upon adoption of FSP SFAS 115-1 and SFAS 124-1, FirstEnergy 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 $10 million of unrealized losses on these available-for-sale securities were reclassified from OCI to earnings upon adoption of this pronouncement. 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. The fair value was determined using the specific identification method.

	2006		2005
	(In millions)
Debt securities:
-Government obligations	$	237	$	281
-Corporate debt securities		123		102
-Mortgage-backed securities		5		-
		365		383
Equity securities		873		711
	$	1,238	$	1,094

The following table summarizes the amortized cost basis, 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	$	360	$	5	$	-	$	365	$	381	$	7	$	5	$	383
Equity securities		652		221		-		873		594		132		15		711
	$	1,012	$	226	$	-	$	1,238	$	975	$	139	$	20	$	1,094

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

Proceeds from the sale of decommissioning trust investments, 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	$	1,067	$	1,023	$	785
Realized gains		118		109		74
Realized losses		90		39		39
Interest and dividend income		36		32		30

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.

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(D)DERIVATIVES-

The Company is exposed to financial risks resulting from the fluctuation of interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. FirstEnergy's Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughout the Company. They are responsible for promoting the effective design and implementation of sound risk management programs. They also oversee compliance with corporate risk management policies and established risk management practices.

The Company accounts for derivative instruments on its Consolidated Balance Sheet at their fair value unless they meet the normal purchase and normal sales criteria. Derivatives that meet that criterion are accounted for on the accrual basis. The changes in the fair value of derivative instruments that do not meet the normal purchase and sales criteria are recorded in current earnings, in AOCI, or as part of the value of the hedged item, depending on whether or not it is designated as part of a hedge transaction, the nature of the hedge transaction and hedge effectiveness.

The Company's primary ongoing hedging activities involve cash flow hedges of electricity and natural gas purchases. The effective portion of such hedges is initially recorded in equity as AOCI and is subsequently recorded in net income, as an operating expense, when the underlying hedged commodities are delivered. AOCI as of December 31, 2006 includes a net deferred loss of $10 million for derivative hedging activity. The $8 million increase from the December 31, 2005 balance of $2 million relates to current hedging activity. Approximately $10 million (after tax) of the current net deferred loss on derivative instruments in AOCI is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments will continue to fluctuate from period to period based on various market factors. Gains and losses from any ineffective portion of the cash flow hedge are recorded directly to earnings. The impact of ineffectiveness on earnings during 2006 and 2005 was not material.

5.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” 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 to determine the actual liability, thereby eliminating the current income-based franchise tax over a five-year period. As a result of the new tax structure, all net deferred taxes that were not expected to reverse during the five-year phase-in period were written off as of June 30, 2005. Since the Company was in a deferred tax liability position, the adjustment to net deferred taxes resulted in a $7 million decrease to income taxes in 2005.

6. POWER SUPPLY AGREEMENTS WITH REGULATED AFFILIATES

Met-Ed and Penelec have been purchasing a portion of their PLR requirements from the Company through a partial requirements wholesale power sales agreement and various amendments. Under these agreements, the Company retained the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec. The Company’s agreements have reduced Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR capacity and energy costs during the term of these agreements with the Company.

On April 7, 2006, the parties entered into a tolling agreement that arose from the Company’s notice to Met-Ed and Penelec that the Company elected to exercise its right to terminate the partial requirements agreement effective midnight December 31, 2006. On November 29, 2006, Met-Ed, Penelec and the Company agreed to suspend the April 7 Tolling Agreement pending resolution of the PPUC’s proceedings regarding the Met-Ed and Penelec Transition Rate Plan cases filed April 10, 2006. Separately, on September 26, 2006, Met-Ed and Penelec successfully conducted a competitive RFP for a portion of their PLR obligations for the period December 1, 2006 through December 31, 2008. The Company was one of the successful bidders in that RFP process and on September 26, 2006, entered into a supplier master agreement to supply a certain portion of Met-Ed’s and Penelec’s PLR requirements at market prices that substantially exceed the fixed price in the partial requirements agreements.

39

Based on the outcome of the Transition Rate Plan filing, Met-Ed, Penelec and the Company agreed to restate the partial requirements power sales agreement effective January 1, 2007. The restated agreement incorporates the same fixed price for residual capacity and energy supplied by the Company as in the prior arrangements between the parties and automatically extends for successive one-year terms unless any party gives 60 days’ notice prior to the end of the year. The restated agreement also allows Met-Ed and Penelec to sell the output of their NUG generation to the market and requires the Company to provide energy at fixed prices to replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec to satisfy their PLR obligations. The parties also have separately terminated the tolling, suspension and supplier master agreements in connection with the restatement of the partial requirements agreement. Accordingly, the energy that would have been supplied under the supplier master agreement will now be provided under the restated partial requirements agreement.

On November 18, 2004, the FERC issued an order eliminating the RTOR for transmission service between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a SECA mechanism to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and the Company participated in the FERC hearings held in May 2006 concerning the calculation and imposition of the SECA charges. The Presiding Judge issued an Initial Decision on August 10, 2006, rejecting the compliance filings made by the RTOs and transmission owners, ruling on various issues and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the Initial Decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC in early 2007.

On November 1, 2005, the Company filed two PSAs for approval with the FERC. One PSA required the Company 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 the Company if the Ohio CBP results in a lower price for retail customers. A similar PSA between the Company and Penn permits Penn to obtain its PLR power requirements from the Company at a fixed price equal to the retail generation price during 2006.

On December 29, 2005, the FERC issued an order setting the two PSAs for hearing. The order criticized the Ohio CBP, and required the Company 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 the Company 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. The Company, 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 PSAs with the Company. Under the Ohio PSA, 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 the Company no more than the lower of (i) the sum of the retail generation charge, the rate stabilization charge, the fuel recovery mechanism charge, and the Company’s 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 the Company to provide this power. The Company billed the Ohio Companies for the additional amount payable to the Company for incremental fuel costs on power supplied during 2006. The total power supply cost billed by the Company 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 the Company under the Penn PSA can be no greater than the generation component of charges for retail PLR load in Pennsylvania. The modifications to the Ohio and Pennsylvania PSAs became effective January 1, 2006. The Penn PSA 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, the Company 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, the Company 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 request for rehearing was filed.

40

7.CAPITALIZATION

(A)RETAINED EARNINGS-

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

(B) LONG-TERM DEBT-

The Company has various debt covenants under its financing arrangements. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on debt and the maintenance of certain financial ratios. There also exist cross-default provisions among financing arrangements of FirstEnergy and the Company.

Sinking fund requirements for maturing long-term debt for the next five years are:

	(In millions)
2007	$	1,470
2008		-
2009		-
2010		15
2011		-

Included in the table above are amounts for certain variable interest rate pollution control revenue bonds that have provisions by which individual debt holders may "put back" the respective debt to the Company for redemption prior to its maturity date. These amounts are $1.470 billion and $15 million in 2007 and 2010, respectively, representing the next time the debt holders may exercise this provision.

Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank LOCs of $1.484 billion as of December 31, 2006 to pay principal of, or interest on, the applicable pollution control revenue bonds. To the extent that drawings are made under the LOCs, FGCO and NGC are entitled to a credit against their obligation to repay those bonds. FGCO and NGC pay annual fees of 0.550% to 0.775% of the amounts of the LOCs to the issuing banks and are obligated to reimburse the banks for any drawings thereunder. These obligations are currently guaranteed by FirstEnergy.

8. ASSET RETIREMENT OBLIGATIONS

The Company has recognized applicable legal obligations under SFAS 143 for nuclear power plant decommissioning, reclamation of a sludge disposal pond and closure of two coal ash disposal sites. In addition, the Company has recognized conditional retirement obligations (primarily for asbestos remediation) in accordance with FIN 47, which was implemented on December 31, 2005.

The ARO liability of $760.2 million as of December 31, 2006 primarily relates to the nuclear decommissioning of the Beaver Valley, Davis-Besse, and Perry nuclear generating facilities. The obligation to decommission these units was developed based on site specific studies performed by an independent engineer. The Company uses an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.

In 2005, the Company revised the ARO associated with Beaver Valley Units 1 and 2, Davis-Besse and Perry, as a result of updated decommissioning studies. The present value of revisions in the estimated cash flows associated with projected decommissioning costs increased the ARO for Beaver Valley Unit 1 by $21 million and decreased the ARO for Beaver Valley Unit 2 by $22 million, resulting in a net decrease in the ARO liability and corresponding plant asset of $1 million. The present value of revisions in the estimated cash flows associated with projected decommissioning costs decreased the ARO and corresponding plant asset for Davis-Besse and Perry by $21 million and $57 million, respectively.

The Company identified applicable legal obligations as defined under the new standard at its active and retired generating units, identifying asbestos remediation as the primary conditional ARO. As a result of adopting FIN 47 in December 2005, the Company recorded a conditional ARO liability of $16 million (including accumulated accretion for the period from the date the liability was incurred to the date of adoption), an asset retirement cost of $4 million (recorded as part of the carrying amount of the related long-lived asset) and accumulated depreciation of $1 million. The remaining cumulative effect adjustment for unrecognized depreciation and accretion of $14 million was charged to income ($9 million, net of tax) for the year ended December 31, 2005.

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

ARO Reconciliation	2006			2005
	(In millions)
Balance at beginning of year	$	716		$	715
Accretion		46			64
Revisions in estimated cash flows		(2	)		(79	)
FIN 47 ARO upon adoption		-			16
Balance at end of year	$	760		$	716

9. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT

The Company had approximately $1.0 billion of short-term indebtedness as of December 31, 2006, comprised of borrowings from affiliates.

On August 24, 2006, the Company, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec and ATSI, as Borrowers, entered into a new $2.75 billion five-year revolving credit facility (included in the borrowing capability table above), which replaced FirstEnergy’s prior $2 billion credit facility. 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 sub-limit, as well as applicable regulatory and other limitations. The Company is currently unable to borrow under the facility, but it will have the capacity to borrow up to $250 million when it is able to deliver notice to the administrative agent that either the Company has senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody’s or that FirstEnergy has guaranteed the Company’s obligations under the facility.

The weighted average interest rates on short-term borrowings outstanding as of December 31, 2006 and 2005 were 5.62% and 4.01% respectively.

10.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 owned interests in the Beaver Valley, Davis-Besse and Perry plants, the Company’s maximum potential assessment under the industry retrospective rating plan (assuming the other affiliates with leasehold interests in Beaver Valley Unit 2 and Perry contribute their proportionate shares of any assessments under the retrospective rating plan) would be $350 million per incident but not more than $52 million in any one year for each incident.

The Company is also insured under policies for each nuclear plant. Under these policies, up to $2.75 billion is provided for property damage and decontamination costs. The Company has also obtained approximately $1.7 billion of insurance coverage for replacement power costs. Under these policies, the Company can be assessed a maximum of approximately $62 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. On September 30, 2003, FirstEnergy tendered a Proof of Loss under the Nuclear Electric Insurance Limited (NEIL) policies for property damage and accidental outage losses associated with the extended outage at the Davis-Besse plant which began in February 2002. In December 2004, NEIL denied FirstEnergy’s claim. FirstEnergy requested binding arbitration under the policies and has submitted expert testimony to support its claim. Under NEIL’s policies, the arbitrators shall award reasonable attorney’s fees and costs to the prevailing party.

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, 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.

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(B)ENVIRONMENTAL MATTERS-

Various federal, state and local authorities regulate FirstEnergy, the Company and their respective subsidiaries with regard to air and water quality and other environmental matters. The effects of compliance on the Company with regard to environmental matters could have a material adverse effect on its earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, the Company believes it is in compliance with existing regulations but is unable to predict future changes in regulatory policies and what, if any, the effects of such changes would be. The Company estimates additional capital expenditures for environmental compliance of approximately $1.8 billion for 2007 through 2011.

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

Clean Air Act Compliance

The Company is required to meet federally approved SO₂ emissions regulations. Violations of such regulations can result in shutdown of a generating unit involved and/or civil or criminal penalties of up to $32,500 for each day a unit is in violation. The EPA has an interim enforcement policy for SO₂ regulations in Ohio that allows for compliance based on a 30-day averaging period. The Company believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the Clean Air Act. The Company has disputed those alleged violations based on its Clean Air Act permit, the Ohio SIP and other information provided at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. Our affiliate, TE, owned the Bay Shore Power Plant at the time of the alleged violation and that we now own and operate.

The Company complies with SO₂ reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NO_X reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NO_X reductions at the Company's facilities. The EPA's NO_X Transport Rule imposes uniform reductions of NO_X emissions (an approximate 85% reduction in utility plant NO_X emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NO_X emissions are contributing significantly to ozone levels in the eastern United States. The Company believes its facilities also are complying with the NO_X budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and fine particulate matter. In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR provided each affected state until 2006 to develop implementing regulations to achieve additional reductions of NO_X and SO₂ emissions in two phases (Phase I in 2009 for NO_X, 2010 for SO₂ and Phase II in 2015 for both NO_X and SO₂). The Company's Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to caps on SO₂ and NO_X emissions, whereas its New Jersey fossil-fired generation facility will be subject to only a cap on NO_X emissions. According to the EPA, SO₂ emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO₂ emissions in affected states to just 2.5 million tons annually. NO_X emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NO_X cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which the Company and its subsidiaries operate affected facilities.

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Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, mercury emissions will be capped nationally at 38 tons by 2010 (as a "co-benefit" from implementation of SO₂ and NO_X emission caps under the EPA's CAIR program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the CAMR have been challenged in the United States Court of Appeals for the District of Columbia. The Company's future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which the Company and its subsidiaries operate affected facilities.

The model rules for both the CAIR and the CAMR contemplate an input-based methodology to allocate allowances to affected facilities. Under this approach, allowances would be allocated based on the amount of fuel consumed by the affected sources. The Company would prefer an output-based generation-neutral methodology in which allowances are allocated based on megawatts of power produced, allowing new and non-emitting generating facilities (including renewables and nuclear) to be entitled to their proportionate share of the allowances. Consequently, the Company will be disadvantaged if these model rules were implemented as proposed because the Company’s substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.

Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap and trade approach as in the CAMR, but rather follows a command and control approach imposing emission limits on individual sources. Pennsylvania’s mercury regulation would deprive the Company of mercury emission allowances that were to be allocated to the Mansfield Plant under the CAMR and that would otherwise be available for achieving the Company’s system-wide compliance. The future cost of compliance with these regulations, if approved and implemented, may be substantial.

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, and is now owned by FGCO. 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 Company 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 FirstEnergy fails 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, FGCO and its affiliates, OE and Penn, 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 FGCO and its affiliates, OE and Penn, 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.

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Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote required for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity - the ratio of emissions to economic output - by 18% through 2012. The EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

The Company cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO₂ emissions could require significant capital and other expenditures. The CO₂ emissions per KWH of electricity generated by the Company is lower than many regional competitors due to its diversified generation sources, which include low or non-CO₂ emitting gas-fired and nuclear generators.

On April 2, 2007, the United States Supreme Court found that EPA has the authority to regulate CO₂ emissions from automobiles as “air pollutants” under the Clear Air Act. Although this decision did not address CO₂ emissions from electric generating plants, EPA has similar authority under the Clan Air Act to regulate “air pollutants” from those and other facilities. FirstEnergy cannot estimate the financial impact of possible EPA regulation of CO₂ emissions, although potential restrictions on CO₂ emissions could require significant capital and other expenditures.

Clean Water Act

Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to the Company's plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to the Company's operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.

On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system, and entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. On January 26, 2007, the federal Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to EPA for further rulemaking and eliminated the restoration option from EPA’s regulations. The Company is conducting comprehensive demonstration studies, due in 2008, to determine the operational measures or equipment, if any, necessary for compliance by its facilities with the performance standards. The Company is unable to predict the outcome of such studies or changes in these requirements from the remand to EPA. Depending on the outcome of such studies and EPA’s further rulemaking, the future cost of compliance with these standards may require material capital expenditures.

Regulation of Hazardous Waste

As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste.

Under NRC regulations, the Company and its affiliates, OE and TE, must ensure that adequate funds will be available to decommission their nuclear facilities in proportion to their respective ownership or leased interest in the nuclear units. As of December 31, 2006, FirstEnergy had approximately $1.4 billion (NGC - $1.2 billion and other affiliates - $0.2 billion) invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley and Perry. As part of the application to the NRC to transfer the ownership of these nuclear facilities to NGC, FirstEnergy agreed to contribute another $80 million to these trusts by 2010; $63 million has been recognized as a notes receivable on the Consolidated Balance Sheet. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy plans to seek for these facilities.

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(C)   OTHER LEGAL PROCEEDINGS-

Nuclear Plant Matters

On January 20, 2006, FENOC announced that it had entered into a deferred prosecution agreement with the U.S. Attorney’s Office for the Northern District of Ohio and the Environmental Crimes Section of the Environment and Natural Resources Division of the DOJ related to FENOC’s communications with the NRC during the fall of 2001 in connection with the reactor head issue at the Davis-Besse Nuclear Power Station. Under the agreement, the United States acknowledged FENOC’s extensive corrective actions at Davis-Besse, FENOC’s cooperation during investigations by the DOJ and the NRC, FENOC’s pledge of continued cooperation in any related criminal and administrative investigations and proceedings, FENOC’s acknowledgement of responsibility for the behavior of its employees, and its agreement to pay a monetary penalty. The DOJ agreed to refrain from seeking an indictment or otherwise initiating criminal prosecution of FENOC for all conduct related to the statement of facts attached to the deferred prosecution agreement, as long as FENOC remained in compliance with the agreement, which FENOC has done. A monetary penalty of $28 million (not deductible for income tax purposes) was reflected in NGC’s fourth quarter of 2005 results. The deferred prosecution agreement expired on December 31, 2006.

On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee's failure to take prompt and corrective action. On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Nuclear Power Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.

On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance at the Perry Nuclear Power Plant and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. In the NRC's 2005 annual assessment letter dated March 2, 2006 and associated meetings to discuss the performance of the Perry Nuclear Power Plant on March 14, 2006, the NRC again stated that the Perry Nuclear Power Plant continued to operate in a manner that "preserved public health and safety." However, the NRC also stated that increased levels of regulatory oversight would continue until sustained improvement in the performance of the facility was realized. By two letters dated March 2, 2007, the NRC closed the Confirmatory Action Letter commitments for Perry, the two outstanding white findings, and crosscutting issues. Moreover, the NRC removed Perry from the Multiple Degraded Cornerstone Column of the NRC Action Matrix and placed the plant in the Licensee Response Column (regular agency oversight).

Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to the Company's normal business operations pending against the Company and its subsidiaries, the most significant of which are described above.

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

(D)   FERC MATTERS-

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

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

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

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

The ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils completed the consolidation of these regions into a single new regional reliability organization known as ReliabilityFirst Corporation. ReliabilityFirst began operations as a regional reliability council under NERC on January 1, 2006 and on November 29, 2006 filed a proposed Delegation Agreement with NERC to obtain certification consistent with the final rule as a “regional entity” under the ERO. All of FirstEnergy’s facilities are located within the ReliabilityFirst region and, as a result, ReliabilityFirst is charged with administering the reliability standards as such standards apply to the Company’s facilities. The Company believes it is in compliance with all current NERC reliability standards.

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 13 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.

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 by the Company’s regulated affiliates. If the Company is unable to meet the reliability standards for its facilities in the future, the Company would be required to move into compliance, which, could have a material adverse effect on the Company’s and its subsidiaries’ financial condition, results of operations and cash flows. In addition, failure to comply with the reliability standards approved by the FERC can result in the imposition of fines and civil penalties.

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On March 16, 2007, the FERC issued a final rule approving the 83 mandatory reliability standards. The final rule will take effect on June 4, 2007. The FERC also directed NERC to improve 56 reliability standards. The final rule has not yet been fully evaluated to assess its impact on our operations.

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 established March 30, 2007, as the date for interested parties to submit comments addressing the filing. FESC filed comments on behalf of FES on March 30, 2007. Although there are certain features of the proposal that will need to be refined and/or more fully developed before the Ancillary Services Market will be fully operational, FirstEnergy supports MISO’s proposal to establish a competitive Ancillary Services Market.

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 become effective on May 14, 2007. The final rule has not yet been fully evaluated to assess its impact on FirstEnergy’s operations.

11. 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. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company is currently evaluating the impact of this Statement on its financial statements.

SFAS 157 - “Fair Value Measurements”

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

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

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

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12. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED)

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

	March 31,		June 30,		September 30,		December 31,
Three Months Ended	2006		2006		2006		2006
	(In millions)
Revenues	$	956.5	$	994.0	$	1,109.6	$	951.2
Expenses		866.8		801.8		808.0		756.6
Operating Income		89.7		192.2		301.6		194.6
Other Expense, net		33.1		34.6		19.2		36.2
Income From Continuing Operations Before Income Taxes		56.6		157.6		282.4		158.4
Income Taxes		19.4		59.0		106.2		51.7
Net Income	$	37.2	$	98.6	$	176.2	$	106.7

	March 31,		June 30,			September 30,			December 31,
Three Months Ended	2005		2005			2005			2005
	(In millions)
Revenues	$	960.0	$	936.0		$	1,059.4		$	1,011.9
Expenses		865.4		830.8			926.1			874.5
Operating Income		94.6		105.2			133.3			137.4
Other Expense (Income), net		40.0		28.6			(1.5	)		70.3
Income From Continuing Operations Before Income Taxes		54.6		76.6			134.8			67.1
Income Taxes		20.3		19.9			49.2			35.1
Income From Continuing Operations		34.3		56.7			85.6			32.0
Discontinued Operations (Net of Income Taxes)		6.1		(1.0	)		0.5			(0.2	)
Cumulative Effect of a Change in Accounting Principle
(Net of Income Taxes)		-		-			-			(8.8	)
Net Income	$	40.4	$	55.7		$	86.1		$	23.0

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