Edgar Filing: FIRSTENERGY CORP

Form 10Q Dated March 31, 2007

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2007

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from

Commission	Registrant; State of Incorporation;	I.R.S. Employer
File Number	Address; and Telephone Number	Identification No.

333-21011	FIRSTENERGY CORP.	34-1843785
	(An Ohio Corporation)
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-2578	OHIO EDISON COMPANY	34-0437786
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-2323	THE CLEVELAND ELECTRIC ILLUMINATING COMPANY	34-0150020
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3583	THE TOLEDO EDISON COMPANY	34-4375005
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3141	JERSEY CENTRAL POWER & LIGHT COMPANY	21-0485010
	(A New Jersey Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-446	METROPOLITAN EDISON COMPANY	23-0870160
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3522	PENNSYLVANIA ELECTRIC COMPANY	25-0718085
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

Indicate by check mark whether each of the registrants (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes (X) No ( )

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer (X)	FirstEnergy Corp.
Accelerated Filer ( )	N/A
Non-accelerated Filer (X)	Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes ( ) No (X)

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:

	OUTSTANDING
CLASS	AS OF MAY 9, 2007
FirstEnergy Corp., $.10 par value	304,835,407
Ohio Edison Company, no par value	60
The Cleveland Electric Illuminating Company, no par value	67,930,743
The Toledo Edison Company, $5 par value	29,402,054
Jersey Central Power & Light Company, $10 par value	15,009,335
Metropolitan Edison Company, no par value	859,500
Pennsylvania Electric Company, $20 par value	5,290,596

FirstEnergy Corp. is the sole holder of Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company common stock.

This combined Form 10-Q is separately filed by FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant, except that information relating to any of the FirstEnergy subsidiary registrants is also attributed to FirstEnergy Corp.

This Form 10-Q includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “believe,” “estimate” and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, the continued ability of FirstEnergy’s regulated utilities to collect transition and other charges or to recover increased transmission costs, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), 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 and oversight) by the NRC and the various state public utility commissions as disclosed in the registrants’ SEC filings, the timing and outcome of various proceedings before the PUCO (including, but not limited to, the distribution rate cases for the Ohio Companies and the successful resolution of the issues remanded to the PUCO by the Ohio Supreme Court regarding the Rate Stabilization Plan) and the PPUC( including the transition rate plan filings for Met-Ed and Penelec and Penn’s default service plan filing), the continuing availability and operation of generating units, the ability of 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 and to experience growth in the distribution business, the ability to access the public securities and other capital markets and the cost of such capital, the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the August 14, 2003 regional power outage, the successful structuring and completion of a potential sale and leaseback transaction for Bruce Mansfield Unit 1 currently under consideration by management, any purchase price adjustment under the accelerated share repurchase program announced March 2, 2007, the risks and other factors discussed from time to time in the registrants’ 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. The registrants expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events, or otherwise.

TABLE OF CONTENTS

		Pages
Glossary of Terms		iii-v

Part I. Financial Information

Items 1. and 2. - Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operations

	Notes to Consolidated Financial Statements	1-21

FirstEnergy Corp.

	Consolidated Statements of Income	22
	Consolidated Statements of Comprehensive Income	23
	Consolidated Balance Sheets	24
	Consolidated Statements of Cash Flows	25
	Report of Independent Registered Public Accounting Firm	26
	Management's Discussion and Analysis of Financial Condition and Results of Operations	27-59

Ohio Edison Company

	Consolidated Statements of Income and Comprehensive Income	60
	Consolidated Balance Sheets	61
	Consolidated Statements of Cash Flows	62
	Report of Independent Registered Public Accounting Firm	63
	Management's Discussion and Analysis of Financial Condition and Results of Operations	64-67

The Cleveland Electric Illuminating Company

	Consolidated Statements of Income and Comprehensive Income	68
	Consolidated Balance Sheets	69
	Consolidated Statements of Cash Flows	70
	Report of Independent Registered Public Accounting Firm	71
	Management's Discussion and Analysis of Financial Condition and Results of Operations	72-75

The Toledo Edison Company

	Consolidated Statements of Income and Comprehensive Income	76
	Consolidated Balance Sheets	77
	Consolidated Statements of Cash Flows	78
	Report of Independent Registered Public Accounting Firm	79
	Management's Discussion and Analysis of Financial Condition and Results of Operations	80-82

TABLE OF CONTENTS (Cont'd)

		Pages


Jersey Central Power & Light Company

	Consolidated Statements of Income and Comprehensive Income	83
	Consolidated Balance Sheets	84
	Consolidated Statements of Cash Flows	85
	Report of Independent Registered Public Accounting Firm	86
	Management's Discussion and Analysis of Financial Condition and Results of Operations	87-89

Metropolitan Edison Company

	Consolidated Statements of Income and Comprehensive Income	90
	Consolidated Balance Sheets	91
	Consolidated Statements of Cash Flows	92
	Report of Independent Registered Public Accounting Firm	93
	Management's Discussion and Analysis of Financial Condition and Results of Operations	94-96

Pennsylvania Electric Company

	Consolidated Statements of Income and Comprehensive Income	97
	Consolidated Balance Sheets	98
	Consolidated Statements of Cash Flows	99
	Report of Independent Registered Public Accounting Firm	100
	Management's Discussion and Analysis of Financial Condition and Results of Operations	101-103

Combined Management’s Discussion and Analysis of Registrant Subsidiaries		104-115

Item 3. Quantitative and Qualitative Disclosures About Market Risk		116

Item 4. Controls and Procedures		116

Part II. Other Information

Item 1. Legal Proceedings		117

Item 1A. Risk Factors		117

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		117

Item 6. Exhibits		117-118

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
Centerior	Centerior Energy Corporation, former parent of CEI and TE, which merged with OE to form FirstEnergy on November 8, 1997
Companies	OE, CEI, TE, JCP&L, Met-Ed and Penelec
FENOC	FirstEnergy Nuclear Operating Company, operates nuclear generating facilities
FES	FirstEnergy Solutions Corp., provides energy-related products and services
FESC	FirstEnergy Service Company, provides legal, financial, and other corporate support services
FGCO	FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities
FirstEnergy	FirstEnergy Corp., a public utility holding company
FSG	FirstEnergy Facilities Services Group, LLC, former parent company of several heating, ventilation, air conditioning and energy management companies
GPU	GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on November 7, 2001
JCP&L	Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
JCP&L Transition Funding	JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition bonds
JCP&L Transition Funding II	JCP&L Transition Funding II LLC, a Delaware limited liability company and issuer of transition bonds
Met-Ed	Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
MYR	MYR Group, Inc., a utility infrastructure construction service company
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
PNBV	PNBV Capital Trust, a special purpose entity created by OE in 1996
Shippingport	Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
TEBSA	Termobarranquilla S.A., Empresa de Servicios Publicos

The following abbreviations and acronyms are used to identify frequently used terms in this report:

ALJ	Administrative Law Judge
AOCL	Accumulated Other Comprehensive Loss
APB	Accounting Principles Board
APB 12	APB Opinion No. 12, “Omnibus Opinion - 1967”
ARO	Asset Retirement Obligation
B&W	Babcock & Wilcox Company
Bechtel	Bechtel Power Corporation
BGS	Basic Generation Service
CAIR	Clean Air Interstate Rule
CAL	Confirmatory Action Letter
CAMR	Clean Air Mercury Rule
CBP	Competitive Bid Process
CO₂	Carbon Dioxide
DOJ	United States Department of Justice
DRA	Division of Ratepayer Advocate
ECAR	East Central Area Reliability Coordination Agreement
EITF	Emerging Issues Task Force
EITF 06-10	EITF Issue No. 06-10, “Accounting for Deferred Compensation and Postretirement Benefit Aspects of Collateral Split-Dollar Life Insurance Arrangements”
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

iii

FIN 46R	FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities"
FIN 47	FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"
FIN 48	FIN 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109”
Fitch	Fitch Ratings, Ltd.
FMB	First Mortgage Bonds
GAAP	Accounting Principles Generally Accepted in the United States
GHG	Greenhouse Gases
IRS	Internal Revenue Service
kV	Kilovolt
KWH	Kilowatt-hours
LOC	Letter of Credit
MEIUG	Met-Ed Industrial Users Group
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service
MOU	Memorandum of Understanding
MW	Megawatts
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NJBPU	New Jersey Board of Public Utilities
NOAC	Northwest Ohio Aggregation Coalition
NOPR	Notice of Proposed Rulemaking
NOV	Notice of Violation
NO_X	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
NUG	Non-Utility Generation
NUGC	Non-Utility Generation Charge
OCA	Office of Consumer Advocate
OCC	Office of the Ohio Consumer’s Counsel
OVEC	Ohio Valley Electric Corporation
PCAOB	Public Company Accounting Oversight Board
PICA	Penelec Industrial Customer Alliance
PJM	PJM Interconnection L. L. C.
PLR	Provider of Last Resort
PPUC	Pennsylvania Public Utility Commission
PRP	Potentially Responsible Party
PSA	Power Supply Agreements
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act of 1935
RCP	Rate Certainty Plan
RFP	Request for Proposal
RSP	Rate Stabilization Plan
RTC	Regulatory Transition Charge
RTO	Regional Transmission Organization
RTOR	Regional Through and Out Rates
S&P	Standard & Poor’s Ratings Service
SBC	Societal Benefits Charge
SEC	U.S. Securities and Exchange Commission
SECA	Seams Elimination Cost Adjustment
SFAS	Statement of Financial Accounting Standards
SFAS 106	SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”
SFAS 107	SFAS No. 107, “Disclosure about Fair Value of Financial Instruments”
SFAS 109	SFAS No. 109, “Accounting for Income Taxes”
SFAS 123(R)	SFAS No. 123(R), "Share-Based Payment"
SFAS 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 143	SFAS No. 143, "Accounting for Asset Retirement Obligations"
SFAS 157	SFAS No. 157, “Fair Value Measurements”
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
SNCR	Selective Non-Catalytic Reduction
SO₂	Sulfur Dioxide
SRM	Special Reliability Master
TBC	Transition Bond Charge
TMI-2	Three Mile Island Unit 2
VIE	Variable Interest Entity

PART I. FINANCIAL INFORMATION

ITEMS 1. AND 2. FINANCIAL STATEMENTS AND MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRSTENERGY CORP. AND SUBSIDIARIES

OHIO EDISON COMPANY AND SUBSIDIARIES

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES

THE TOLEDO EDISON COMPANY AND SUBSIDIARY

JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARIES

METROPOLITAN EDISON COMPANY AND SUBSIDIARIES

PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. ORGANIZATION AND BASIS OF PRESENTATION

FirstEnergy's principal business is the holding, directly or indirectly, of all of the outstanding common stock of its eight principal electric utility operating subsidiaries: OE, CEI, TE, Penn, ATSI, JCP&L, Met-Ed and Penelec. Penn is a wholly owned subsidiary of OE. FirstEnergy’s consolidated financial statements also include its other subsidiaries: FENOC, FES and its subsidiaries FGCO and NGC, and FESC.

FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, FERC and, as applicable, the PUCO, PPUC and NJBPU. 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.

These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 2006 for FirstEnergy and the Companies. The consolidated unaudited financial statements of FirstEnergy and each of the Companies reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain businesses divested in 2006 have been classified as discontinued operations on the Consolidated Statements of Income (see Note 3). As discussed in Note 12, interim period segment reporting in 2006 was reclassified to conform with the current year business segment organizations and operations. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.

FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 7) when it is determined to be the VIE's primary beneficiary. Investments in non-consolidated affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control (20-50% owned companies, joint ventures and partnerships) are accounted for under the equity method. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income. Certain prior year amounts have been reclassified to conform to the current year presentation.

FirstEnergy's and the Companies' independent registered public accounting firm has performed reviews of, and issued reports on, these consolidated interim financial statements in accordance with standards established by the PCAOB. Pursuant to Rule 436(c) under the Securities Act of 1933, their reports of those reviews should not be considered a report within the meaning of Section 7 and 11 of that Act, and the independent registered public accounting firm’s liability under Section 11 does not extend to them.

2. EARNINGS PER SHARE

Basic earnings per share of common stock is computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. The pool of stock-based compensation tax benefits is calculated in accordance with SFAS 123(R). On August 10, 2006, FirstEnergy repurchased 10.6 million shares, approximately 3.2%, of its outstanding common stock through an accelerated share repurchase program. The initial purchase price was $600 million, or $56.44 per share. A final purchase price adjustment of $27 million was settled in cash on April 2, 2007. On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding common stock through an additional accelerated share repurchase program with an affiliate of Morgan Stanley and Co., Incorporated at an initial price of $62.63 per share, or a total initial purchase price of approximately $900 million. The final purchase price for this program will be adjusted to reflect the volume weighted average price of FirstEnergy’s common stock during the period of time that the bank will acquire shares to cover its short position, which is approximately one year. The basic and diluted earnings per share calculations for the first quarter of 2007 reflect the impact associated with the March 2007 accelerated share repurchase program. FirstEnergy intends to settle, in cash or shares, any obligation on its part to pay the difference between the average of the daily volume-weighted average price of the shares as calculated under the March 2007 program and the initial price of the shares. The effect of any potential settlement in shares is currently unknown.

Reconciliation of Basic and Diluted				Three Months Ended March 31,
Earnings per Share of Common Stock				2007		2006
			*(In millions, except per share amounts)*
Income from continuing operations				$	290	$	219
Discontinued operations					-		2
Net income available for common shareholders				$	290	$	221

Average shares of common stock outstanding - Basic					314		329
Assumed exercise of dilutive stock options and awards					2		1
Average shares of common stock outstanding - Dilutive					316		330

Earnings per share:
	Basic earnings per share:
		Earnings from continuing operations		$	0.92	$	0.67
		Discontinued operations			-		-
		Net earnings per basic share		$	0.92	$	0.67

	Diluted earnings per share:
		Earnings from continuing operations		$	0.92	$	0.67
		Discontinued operations			-		-
		Net earnings per diluted share		$	0.92	$	0.67

3. DIVESTITURES AND DISCONTINUED OPERATIONS

In 2006, FirstEnergy sold its remaining FSG subsidiaries (Roth Bros., Hattenbach, Dunbar, Edwards and RPC) for an aggregate net after-tax gain of $2.2 million. Hattenbach, Dunbar, Edwards, and RPC are included in discontinued operations for the quarter ended March 31, 2006; Roth Bros. does not meet the criteria for that classification.

In March 2006, FirstEnergy sold 60% of its interest in MYR for an after-tax gain of $0.2 million. In June 2006, as part of the March agreement, FirstEnergy sold an additional 1.67% interest. As a result of the March sale, FirstEnergy deconsolidated MYR in the first quarter of 2006 and accounted for its remaining 38.33% interest under the equity method. In the fourth quarter of 2006, FirstEnergy sold its remaining MYR interest for an after-tax gain of $8.6 million. The income for the period that MYR was accounted for as an equity method investment has not been included in discontinued operations; however, results in the first quarter of 2006 prior to the initial sale in March 2006, including the gain on the sale, are reported as discontinued operations.

Revenues associated with discontinued operations were $140 million in first quarter of 2006. The following table summarizes the net income (loss) included in "Discontinued Operations" on the Consolidated Statements of Income for the three months ended March 31, 2006 (in millions):

FSG subsidiaries	$	(1	)
MYR		3
Income from discontinued operations	$	2

4. DERIVATIVE INSTRUMENTS

FirstEnergy 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 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 for 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.

FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheet at their fair value unless they meet the normal purchase and normal sales criterion. 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 criterion are recorded as other expense, as AOCL, 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.

FirstEnergy hedges anticipated transactions using cash flow hedges. Such transactions include hedges of anticipated electricity and natural gas purchases and anticipated interest payments associated with future debt issues. The effective portion of such hedges are initially recorded in equity as other comprehensive income or loss and are subsequently included in net income as the underlying hedged commodities are delivered or interest payments are made. Gains and losses from any ineffective portion of cash flow hedges are included directly in earnings.

The net deferred losses of $45 million included in AOCL as of March 31, 2007, for derivative hedging activity, as compared to the December 31, 2006 balance of $58 million of net deferred losses, resulted from a net $9 million decrease related to current hedging activity and a $4 million decrease due to net hedge losses reclassified into earnings during the three months ended March 31, 2007. Based on current estimates, approximately $7 million (after tax) of the net deferred losses on derivative instruments in AOCL as of March 31, 2007 is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuate from period to period based on various market factors.

FirstEnergy has entered into swaps that have been designated as fair value hedges of fixed-rate, long-term debt issues to protect against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates received, and interest payment dates match those of the underlying debt obligations. In prior years, FirstEnergy has unwound swaps, the gains and losses are amortized in earnings over the remaining maturity of each respective hedged security as adjustments to interest expense. As of March 31, 2007, FirstEnergy had interest rate swaps with an aggregate notional value of $750 million and a fair value of $(24) million.

During 2006 and the first three months of 2007, FirstEnergy entered into several forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with the anticipated issuances of fixed-rate, long-term debt securities for one or more of its subsidiaries during 2007 - 2008 as outstanding debt matures. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. During the first three months of 2007, FirstEnergy terminated swaps with a notional value of $250 million for which it paid $3 million, all of which was deemed effective. FirstEnergy will recognize the loss over the life of the associated future debt. As of March 31, 2007, FirstEnergy had forward swaps with an aggregate notional amount of $475 million and a long-term debt securities fair value of $(2) million.

5. ASSET RETIREMENT OBLIGATIONS

FirstEnergy 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, FirstEnergy has recognized conditional retirement obligations (primarily for asbestos remediation) in accordance with FIN 47.

The ARO liability of $1.2 billion as of March 31, 2007 is primarily related to the nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. The obligation to decommission these units was developed based on site specific studies performed by an independent engineer. FirstEnergy utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.

FirstEnergy maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of March 31, 2007, the fair value of the decommissioning trust assets was $2.0 billion.

The following tables analyze changes to the ARO balance during the first quarters of 2007 and 2006, respectively.

ARO Reconciliation	FirstEnergy		OE		CEI		TE		JCP&L		Met-Ed		Penelec
	*(In millions)*
Balance, January 1, 2007	$	1,190	$	88	$	2	$	27	$	84	$	151	$	77
Liabilities incurred		-		-		-		-		-		-		-
Liabilities settled		-		-		-		-		-		-		-
Accretion		18		1		-		-		2		2		1
Revisions in estimated cash flows		-		-		-		-		-		-		-
Balance, March 31, 2007	$	1,208	$	89	$	2	$	27	$	86	$	153	$	78

Balance, January 1, 2006	$	1,126	$	83	$	8	$	25	$	80	$	142	$	72
Liabilities incurred		-		-		-		-		-		-		-
Liabilities settled		-		-		-		-		-		-		-
Accretion		18		1		-		-		1		2		1
Revisions in estimated cash flows		4		-		-		-		-		-		-
Balance, March 31, 2006	$	1,148	$	84	$	8	$	25	$	81	$	144	$	73

6. PENSION AND OTHER POSTRETIREMENT BENEFITS

FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees. The trusteed plans provide defined benefits based on years of service and compensation levels. The Company’s funding policy is based on actuarial computations using the projected unit credit method. On January 2, 2007, FirstEnergy made a $300 million voluntary cash contribution to its qualified pension plan. Projections indicate that additional cash contributions are not expected to be required before 2016. FirstEnergy also 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 available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension benefits and other postretirement benefits from the time employees are hired until they become eligible to receive those benefits. During 2006, FirstEnergy amended the health care plan effective in 2008 to cap the monthly contribution for many of the retirees and their spouses receiving subsidized health care coverage. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.

The components of FirstEnergy's net periodic pension cost and other postretirement benefit cost (including amounts capitalized) for the three months ended March 31, 2007 and 2006, consisted of the following:

	Pension Benefits						Other Postretirement Benefits
	2007			2006			2007			2006
				*(In millions)*
Service cost	$	21		$	21		$	5		$	9
Interest cost		71			66			17			26
Expected return on plan assets		(112	)		(99	)		(13	)		(12	)
Amortization of prior service cost		2			2			(37	)		(19	)
Recognized net actuarial loss		10			15			12			14
Net periodic cost (credit)	$	(8)		$	5		$	(16	)	$	18

Pension and postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. The Companies capitalize employee benefits related to construction projects. The net periodic pension costs and net periodic postretirement benefit costs (including amounts capitalized) recognized by each of the Companies for the three months ended March 31, 2007 and 2006 were as follows:

	Pension Benefit Cost (Credit)						Other Postretirement Benefit Cost (Credit)
	2007			2006			2007			2006
				*(In millions)*
OE	$	(4.0	)	$	(1.5	)	$	(2.7	)	$	4.2
CEI		0.3			1.0			1.0			2.8
TE		-			0.2			1.2			2.0
JCP&L		(2.1	)		(1.4	)		(4.0	)		0.6
Met-Ed		(1.7	)		(1.7	)		(2.5	)		0.7
Penelec		(2.6	)		(1.3	)		(3.2	)		1.8
Other FirstEnergy subsidiaries		2.5			9.9			(5.7	)		6.1
	$	(7.6	)	$	5.2		$	(15.9	)	$	18.2

7. VARIABLE INTEREST ENTITIES

FIN 46R addresses the consolidation of VIEs, including special-purpose entities, that are not controlled through voting interests or in which the equity investors do not bear the entity's residual economic risks and rewards. FirstEnergy and its subsidiaries consolidate VIEs when they are determined to be the VIE's primary beneficiary as defined by FIN 46R.

Leases

FirstEnergy’s consolidated financial statements include PNBV and Shippingport, VIEs created in 1996 and 1997, respectively, to refinance debt originally issued in connection with sale and leaseback transactions. PNBV and Shippingport financial data are included in the consolidated financial statements of OE and CEI, respectively.

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

OE, CEI and TE are exposed to losses under the applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. OE, CEI and TE each have a maximum exposure to loss under these provisions of approximately $817 million, $960 million and $960 million, respectively, which represents the net amount of casualty value payments upon the occurrence of specified casualty events that render the applicable plant worthless. Under the applicable sale and leaseback agreements, OE, CEI and TE have net minimum discounted lease payments of $646 million, $89 million and $500 million, respectively, that would not be payable if the casualty value payments are made.

Power Purchase Agreements

In accordance with FIN 46R, FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to the Companies and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec, maintains approximately 30 long-term power purchase agreements with NUG entities. The agreements were entered into pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.

FirstEnergy has determined that for all but eight of these entities, neither JCP&L, Met-Ed nor Penelec have variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of FIN 46R. JCP&L, Met-Ed or Penelec may hold variable interests in the remaining eight entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants. As required by FIN 46R, FirstEnergy periodically requests from these eight entities the information necessary to determine whether they are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. FirstEnergy has been unable to obtain the requested information, which in most cases was deemed by the requested entity to be proprietary. As such, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R.

Since FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs it incurs for power. FirstEnergy expects any above-market costs it incurs to be recovered from customers. As of March 31, 2007, the net projected above-market loss liability recognized for these eight NUG agreements was $155 million. Purchased power costs from these entities during the first quarters of 2007 and 2006 are shown in the table below:

	Three Months Ended
	March 31,
	2007		2006
	*(In millions)*
JCP&L	$	20	$	15
Met-Ed		15		16
Penelec		8		8
	$	43	$	39

Transition Bonds

The consolidated financial statements of FirstEnergy and JCP&L include the results of JCP&L Transition Funding and JCP&L Transition Funding II, wholly owned limited liability companies of JCP&L. In June 2002, JCP&L Transition Funding sold $320 million of transition bonds to securitize the recovery of JCP&L's bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. In August 2006, JCP&L Transition Funding II sold $182 million of transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS.

JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. As of March 31, 2007, $420 million of the transition bonds are outstanding. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consists primarily of bondable transition property.

Bondable transition property represents the irrevocable right under New Jersey law of a utility company to charge, collect and receive from its customers, through a non-bypassable TBC, the principal amount and interest on transition bonds and other fees and expenses associated with their issuance. JCP&L sold its bondable transition property to JCP&L Transition Funding and JCP&L Transition Funding II and, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to separate servicing agreements with JCP&L Transition Funding and JCP&L Transition Funding II. For the two series of transition bonds, JCP&L is entitled to aggregate quarterly servicing fees of $157,000 that is payable from TBC collections.

8. INCOME TAXES

On January 1, 2007, FirstEnergy adopted FIN 48, which provides guidance for accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109. This interpretation prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken on a company’s tax return. FIN 48 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 is a two-step process. The first step is to 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 is to measure a tax position that meets the more likely than not recognition threshold to determine the amount of income tax benefit to recognize in the financial statements.

As of January 1, 2007, the total amount of FirstEnergy’s unrecognized tax benefits was $268 million. FirstEnergy recorded a $2.7 million cumulative effect adjustment to the January 1, 2007 balance of retained earnings to increase reserves for uncertain tax positions. Of the total amount of unrecognized income tax benefits, $92 million would favorably affect FirstEnergy’s effective tax rate upon recognition. The majority of items that would not affect the effective tax rate would be purchase accounting adjustments to goodwill upon recognition. During the first quarter of 2007, there were no material changes to FirstEnergy’s unrecognized tax benefits. The entire balance is included in other non-current liabilities.

FIN 48 also requires companies to recognize interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes, consistent with its policy prior to implementing FIN 48. As of January 1, 2007, the net amount of interest accrued was $34 million. During the first quarter of 2007, there were no material changes to the amount of interest accrued.

FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state tax authorities. All state jurisdictions are open from 2001-2006. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items are under appeal. The federal audit for years 2004 and 2005 began in June 2006 and is not expected to close before December 2007. The IRS began auditing the year 2006 in April 2006 under its Compliance Assurance Process experimental program, which is not expected to close before December 2007. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy’s financial condition or results of operations.

In the first quarter of 2007, OE’s income taxes included an immaterial adjustment applicable to prior periods of $7.2 million related to an inter-company federal tax allocation arrangement between FirstEnergy and its subsidiaries.

9. COMMITMENTS, GUARANTEES AND CONTINGENCIES

(A) GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As of March 31, 2007, outstanding guarantees and other assurances aggregated approximately $4.3 billion, consisting of contract guarantees - $2.5 billion, surety bonds - $0.1 billion and LOCs - $1.7 billion.

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for subsidiary financings or refinancings of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.9 billion (included in the $2.5 billion discussed above) as of March 31, 2007 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating-downgrade or “material adverse event” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. As of March 31, 2007, FirstEnergy's maximum exposure under these collateral provisions was $392 million.

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $106 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction jobs, environmental commitments and various retail transactions.

The Companies, with the exception of TE and JCP&L, each have a wholly owned subsidiary whose borrowings are secured by customer accounts receivable purchased from its respective parent company. The CEI subsidiary's borrowings are also secured by customer accounts receivable purchased from TE. Each subsidiary company has its own receivables financing arrangement and, as a separate legal entity with separate creditors, would have to satisfy its obligations to creditors before any of its remaining assets could be available to its parent company.

			Borrowing
Subsidiary Company	Parent Company		Capacity
			*(In millions)*
OES Capital, Incorporated		OE	$	170
Centerior Funding Corp.		CEI		200
Penn Power Funding LLC		Penn		25
Met-Ed Funding LLC		Met-Ed		80
Penelec Funding LLC		Penelec		75
			$	550

FirstEnergy has also guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has also provided an LOC ($27 million as of March 31, 2007), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.

(B) ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergy with regard to environmental matters could have a material adverse effect on FirstEnergy's 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, FirstEnergy 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. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $1.8 billion for 2007 through 2011.

FirstEnergy 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 FirstEnergy’s determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.

Clean Air Act Compliance

FirstEnergy is required to meet federally-approved SO₂ emissions regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $32,500 for each day the 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. FirstEnergy 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. FirstEnergy 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.

FirstEnergy 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 FirstEnergy'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. FirstEnergy believes its facilities are also 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). FirstEnergy'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 FirstEnergy operates 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 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. FirstEnergy'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 FirstEnergy operates affected facilities.

The model rules for both CAIR and 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. FirstEnergy 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, FirstEnergy will be disadvantaged if these model rules were implemented as proposed because FirstEnergy’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 FES of mercury emission allowances that were to be allocated to the Mansfield Plant under the CAMR and that would otherwise be available for achieving FirstEnergy system-wide compliance. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at Mansfield, FirstEnergy’s only Pennsylvania power plant, until 2015, if at all.

W. H. Sammis Plant

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

On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the New Source Review litigation. This settlement agreement, which is in the form of a consent decree, was approved by the Court on July 11, 2005, and requires reductions of NO_X and SO₂ emissions at the W. H. Sammis Plant and other FES 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, FirstEnergy 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 during 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 FirstEnergy 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 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. At the international level, efforts have begun to develop climate change agreements for post-2012 GHG reductions. 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.

At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO₂ emissions from automobiles as “air pollutants” under the Clean Air Act. Although this decision did not address CO₂ emissions from electric generating plants, the EPA has similar authority under the Clean Air Act to regulate “air pollutants” from those and other facilities.

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

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 FirstEnergy's plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FirstEnergy'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. FirstEnergy 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. FirstEnergy 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, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of March 31, 2007, FirstEnergy had approximately $1.4 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. 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.

The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of March 31, 2007, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Total liabilities of approximately $87 million (JCP&L - $59 million, TE - $3 million, CEI - $1 million, and other subsidiaries - $24 million) have been accrued through March 31, 2007.

(C) OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation

In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four of New Jersey’s electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory.

In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision on July 8, 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, New Jersey. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, on March 7, 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. In late March 2007, JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of March 31, 2007.

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

FirstEnergy companies also are defending four separate complaint cases before the PUCO relating to the August 14, 2003 power outages. Two of those cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Two other pending PUCO complaint cases were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of these cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc., as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. A fifth case in which a carrier sought reimbursement for claims paid to insureds was voluntarily dismissed by the claimant in April 2007. A sixth case involving the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003 was dismissed. The four cases were consolidated for hearing by the PUCO in an order dated March 7, 2006. In that order the PUCO also limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy as a defendant; and ruled that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence. In response to a motion for rehearing filed by one of the claimants, the PUCO ruled on April 26, 2006 that the insurance company claimants, as insurers, may prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities that provide their service. The PUCO denied all other motions for rehearing. The plaintiffs in each case have since filed amended complaints and the named FirstEnergy companies have answered and also have filed a motion to dismiss each action. On September 27, 2006, the PUCO dismissed certain parties and claims and otherwise ordered the complaints to go forward to hearing. The cases have been set for hearing on January 8, 2008.

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

FirstEnergy was also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy were based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. None of FirstEnergy’s subsidiaries serve customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss. The plaintiff has not appealed.

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

Nuclear Plant Matters

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. 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 (routine agency oversight).

On April 30, 2007, the Union of Concerned Scientists (UCS) filed a petition with the NRC under Section 2.206 of the NRC’s regulations based on an expert witness report that FENOC developed for an unrelated insurance arbitration. In December 2006, the expert witness for FENOC prepared a report that analyzed the crack growth rates in control rod drive mechanism penetrations and wastage of the former reactor pressure vessel head at Davis-Besse. Citing the findings in the expert witness' report, the Section 2.206 petition requested that: (1) Davis-Besse be immediately shut down; (2) that the NRC conduct an independent review of the consultant's report and that all pressurized water reactors be shut down until remedial actions can be implemented; and (3) that Davis-Besse’s operating license be revoked.

In a letter dated May 4, 2007, the NRC stated that "the current inspection requirements are sufficient to detect degradation of a reactor pressure vessel head penetration nozzles prior to the development of significant head wastage even if the assumptions and conclusions in the [expert witness] report relating to the wastage of the head at Davis-Besse were applied to all pressurized water reactors." The NRC also indicated that while they are developing a more complete response to the UCS' petition, “the staff informed UCS that, as an initial matter, it has determined that no immediate action with respect to Davis-Besse or other nuclear plant is warranted.” FirstEnergy can provide no assurances as to the ultimate resolution of this matter.

Other Legal Matters

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

On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members. On April 5, 2007, the Court rejected the plaintiffs' request to certify this case as a class action and, accordingly, did not appoint the plaintiffs as class representatives or their counsel as class counsel. The Court has scheduled oral argument for June 25, 2007 to hear the plaintiffs' request for reconsideration of its order denying class certification and request to amend their complaint.

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. JCP&L intends to re-file an appeal again in federal district court once the damages associated with this case are identified at an individual employee level. JCP&L recognized a liability for the potential $16 million award in 2005.

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

10. REGULATORY MATTERS

(A) RELIABILITY INITIATIVES

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

As a result of outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L’s service reliability. In 2004, the NJBPU adopted an MOU that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L’s ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a stipulation that incorporates the final report of an SRM who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The stipulation also incorporates the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L’s Planning and Operations and Maintenance programs and practices (Focused Audit). On February 11, 2005, JCP&L met with the DRA to discuss reliability improvements. The SRM completed his work and issued his final report to the NJBPU on June 1, 2006. JCP&L filed a comprehensive response to the NJBPU on July 14, 2006. JCP&L continues to file compliance reports reflecting activities associated with the MOU and stipulation.

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). A rule adopted by the FERC in 2006 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, which NERC submitted on March 19, 2007.

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, which established the regulatory framework for NERC’s future enforcement program, was approved by the FERC on April 19, 2007.

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. This Delegation Agreement was also approved by the FERC on April 19, 2007. All of FirstEnergy’s facilities are located within the ReliabilityFirst region.

On May 2, 2006, the NERC Board of Trustees adopted eight new cyber security standards that replaced interim standards put in place in the wake of the September 11, 2001 terrorist attacks, and thirteen additional reliability standards. The security standards became effective on June 1, 2006, and the remaining standards become effective during 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. Numerous parties, including FirstEnergy, provided comments on the assessment by February 12, 2007. This filing is pending before the FERC.

On April 4, 2006, NERC submitted a filing with the FERC seeking approval of mandatory reliability standards. On October 20, 2006, the FERC in turn issued a Proposed Rule on the reliability standards. After a period of public review of the proposal, the FERC issued on March 16, 2007 its Final Rule on Mandatory Reliability Standards for the Bulk-Power System. In this ruling, the FERC approved 83 of the 107 mandatory electric reliability standards proposed by NERC, making them enforceable with penalties and sanctions for noncompliance when the rule becomes effective, which is expected by the summer of 2007. The final rule will become effective on June 4, 2007. The FERC also directed NERC to submit improvements to 56 standards, endorsing NERC's process for developing reliability standards and its associated work plan. The 24 standards that were not approved remain pending at the FERC awaiting further information from NERC and its regional entities.

FirstEnergy believes it is in compliance with all current NERC reliability standards. However, based upon a review of the March 16, 2007 Final Rule, it appears that the FERC will eventually adopt stricter NERC reliability standards than those just approved as NERC addresses the FERC's guidance in the Final Rule. The financial impact of complying with the new standards cannot be determined at this time. However, the EPACT required that all prudent costs incurred to comply with the new reliability standards be recovered in rates. If FirstEnergy is unable to meet the reliability standards for its bulk power system in the future, it could have a material adverse effect on FirstEnergy’s and its subsidiaries’ financial condition, results of operations and cash flows.

(B) OHIO

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

On August 31, 2005, the PUCO approved a rider recovery mechanism through which the Ohio Companies may recover all MISO transmission and ancillary service related costs incurred during each year ending June 30. Pursuant to the PUCO’s order, the Ohio Companies, on May 1, 2007, filed revised riders which will automatically become effective on July 1, 2007. The revised riders represent an increase over the amounts collected through the 2006 riders of approximately $64 million annually.

During the period between May 1, 2007 and June 1, 2007, any party may raise issues related to the revised tariffs through an informal resolution process. If not adequately resolved through this process by June 30, 2007, any interested party may file a formal complaint with the PUCO which will be addressed by the PUCO after all parties have been heard. If at the conclusion of either the informal or formal process, adjustments are found to be necessary, such adjustments (with carrying costs) will be included in the Ohio Companies’ next rider filing which must be filed no later than May 1, 2008. No assurance can be given that such formal or informal proceedings will not be instituted.

On May 8, 2007, the Ohio Companies filed with the PUCO a notice of intent to file for an increase in electric distribution rates. The Ohio Companies intend to file the application and rate request with the PUCO on or after June 7, 2007. The requested $334 million increase is expected to be more than offset by the elimination or reduction of transition charges at the time the rates go into effect and would result in lowering the overall non-generation portion of the bill for most Ohio customers. The distribution rate increases reflect capital expenditures since the Ohio Companies’ last distribution rate proceedings, increases in operating and maintenance expenses and recovery of regulatory assets created by deferrals that were approved in prior cases. The new rates, subject to evidentiary hearings at the PUCO, would become effective January 1, 2009 for OE and TE, and May 2009 for CEI.

(C) PENNSYLVANIA

Met-Ed and Penelec have been purchasing a portion of their PLR requirements from FES through a partial requirements wholesale power sales agreement and various amendments. Under these agreements, FES 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 FES 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 FES.

On April 7, 2006, the parties entered into a tolling agreement that arose from FES’ notice to Met-Ed and Penelec that FES elected to exercise its right to terminate the partial requirements agreement effective midnight December 31, 2006. On November 29, 2006, Met-Ed, Penelec and FES agreed to suspend the April 7 tolling agreement pending resolution of the PPUC’s proceedings regarding the Met-Ed and Penelec comprehensive transition rate cases filed April 10, 2006, described below. Separately, on September 26, 2006, Met-Ed and Penelec successfully conducted a competitive RFP for a portion of their PLR obligation for the period December 1, 2006 through December 31, 2008. FES 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.

Based on the outcome of the 2006 comprehensive transition rate filing, as described below, Met-Ed, Penelec and FES 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 FES 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 allows Met-Ed and Penelec to sell the output of NUG generation to the market and requires FES 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 have also 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.

If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for its fixed income securities. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC.

Met-Ed and Penelec made a comprehensive transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out in accordance with the April 7, 2006 tolling agreement described above. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs, but only for those costs incurred during 2006. In this rate filing, Met-Ed and Penelec also requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of the merger savings, with the comprehensive transmission rate filing case.

The PPUC entered its Opinion and Order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, when new transmission rates were effective, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes in NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission expenses and the transmission deferral. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million). Met-Ed and Penelec filed a Petition for Reconsideration on January 26, 2007 on the issues of consolidated tax savings and rate of return on equity. Other parties filed Petitions for Reconsideration on transmission (including congestion), transmission deferrals and rate design issues. On February 8, 2007, the PPUC entered an order granting Met-Ed’s, Penelec’s and the other parties’ petitions for procedural purposes. Due to that ruling, the period for appeals to the Commonwealth Court was tolled until 30 days after the PPUC entered a subsequent order ruling on the substantive issues raised in the petitions. On March 1, 2007, the PPUC issued three orders: 1) a tentative order regarding the reconsideration by the PPUC of its own order; 2) an order denying the Petitions for Reconsideration of Met-Ed, Penelec and the OCA and denying in part and accepting in part the MEIUG’s and PICA’s Petition for Reconsideration; and 3) an order approving the Compliance filing. Comments to the PPUC for reconsideration of its order were filed on March 8, 2007, and the PPUC ruled on the reconsideration on April 13, 2007, making minor changes to rate design as agreed upon by Met-Ed, Penelec and certain other parties.

On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court asking the court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on FirstEnergy’s and their financial condition and results of operations.

As of March 31, 2007, Met-Ed's and Penelec's unrecovered regulatory deferrals pursuant to the 2006 comprehensive transition rate case, the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation were $472 million and $124 million, respectively. Penelec’s $124 million deferral is subject to final resolution of an IRS settlement associated with NUG trust fund proceeds. During the PPUC’s annual audit of Met-Ed’s and Penelec’s NUG stranded cost balances in 2006, it noted a modification to the NUG purchased power stranded cost accounting methodology made by Met-Ed and Penelec. On August 18, 2006, a PPUC Order was entered requiring Met-Ed and Penelec to reflect the deferred NUG cost balances as if the stranded cost accounting methodology modification had not been implemented. As a result of this PPUC order, Met-Ed recognized a pre-tax charge of approximately $10.3 million in the third quarter of 2006, representing incremental costs deferred under the revised methodology in 2005. Met-Ed and Penelec continue to believe that the stranded cost accounting methodology modification is appropriate and on August 24, 2006 filed a petition with the PPUC pursuant to its order for authorization to reflect the stranded cost accounting methodology modification effective January 1, 1999. Hearings on this petition were held in late February 2007 and briefing was completed on March 28, 2007. The ALJ’s initial decision was issued on May 3, 2007 and denied Met-Ed's and Penelec’s request to modify their NUG stranded cost accounting methodology. The companies may file exceptions to the initial decision by May 22, 2007 and parties may reply to those exceptions 10 days thereafter. It is not known when the PPUC may issue a final decision in this matter.

On May 2, 2007, Penn filed a plan with the PPUC for the procurement of PLR supply from June 2008 through May 2011. The filing proposes multiple, competitive RFPs with staggered delivery periods for fixed-price, tranche-based, pay as bid PLR supply to the residential and commercial classes. The proposal phases out existing promotional rates and eliminates the declining block and the demand components on generation rates for residential and commercial customers. The industrial class PLR service will be provided through an hourly-priced service provided by Penn. Quarterly reconciliation of the differences between the costs of supply and revenues from customers is also proposed. The PPUC is requested to act on the proposal no later than November 2007 for the initial RFP to take place in January 2008.

On February 1, 2007, the Governor of Pennsylvania proposed an Energy Independence Strategy (EIS). The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation programs to meet demand growth, a requirement that electric distribution companies acquire power through a "Least Cost Portfolio", the utilization of micro-grids and an optional three year phase-in of rate increases. Since the EIS has only recently been proposed, the final form of any legislation is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations.

(D) NEW JERSEY

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of March 31, 2007, the accumulated deferred cost balance totaled approximately $357 million.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DRA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. A schedule for further NJBPU proceedings has not yet been set.

On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that would prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. Comments on the alternative proposal were submitted on June 15, 2006. On November 3, 2006, the Staff circulated a revised draft proposal to interested stakeholders. Another revised draft was circulated by the NJBPU Staff on February 8, 2007.

New Jersey statutes require that the state periodically undertake a planning process, known as the Energy Master Plan (EMP), to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated with the issuance of a proposed set of objectives which, as to electricity, included the following:

·	Reduce the total projected electricity demand by 20% by 2020;

·	Meet 22.5% of New Jersey’s electricity needs with renewable energy resources by that date;

·	Reduce air pollution related to energy use;

·	Encourage and maintain economic growth and development;

·	Achieve a 20% reduction in both Customer Average Interruption Duration Index and System Average Interruption Frequency Index by 2020;

·	Unit prices for electricity should remain no more than +5% of the regional average price (region includes New York, New Jersey, Pennsylvania, Delaware, Maryland and the District of Columbia); and

·	Eliminate transmission congestion by 2020.

Comments on the objectives and participation in the development of the EMP have been solicited and a number of working groups have been formed to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. EMP working groups addressing 1) energy efficiency and demand response and 2) renewables have completed their assigned tasks of data gathering and analysis. Both groups have provided a report to the EMP Committee. The working groups addressing reliability and pricing issues continue their data gathering and analysis activities. Public stakeholder meetings were held in the fall of 2006 and in early 2007, and further public meetings are expected in the summer of 2007. A final draft of the EMP is expected to be presented to the Governor in the fall of 2007 with further public hearings anticipated in early 2008. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on its operations or those of JCP&L.

On February 13, 2007, the NJBPU Staff issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards. A meeting between the NJBPU Staff and interested stakeholders to discuss the proposal was held on February 15, 2007. On February 22, 2007, the NJBPU Staff circulated a revised proposal upon which discussions with interested stakeholders were held on March 26, 2007. On April 18 and April 23, 2007 the NJBPU staff circulated further revised draft proposals. A schedule for formal proceedings has not yet been established. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, ultimate regulations resulting from these draft proposals may have on its operations or those of JCP&L.

(E) FERC MATTERS

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 the 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 FES 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 the second quarter of 2007.

On January 31, 2005, certain PJM transmission owners made three filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. American Electric Power Company, Inc. filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to refund and hearing procedures. On June 30, 2005, the settling PJM transmission owners filed a request for rehearing of the May 31, 2005 order. On March 20, 2006, a settlement was filed with FERC in the formula rate proceeding that generally accepts the companies' formula rate proposal. The FERC issued an order approving this settlement on April 19, 2006. Hearings in the PJM rate design case concluded in April 2006. On July 13, 2006, an Initial Decision was issued by the ALJ. The ALJ adopted the FERC Trial Staff’s position that the cost of all PJM transmission facilities should be recovered through a postage stamp rate. The ALJ recommended an April 1, 2006 effective date for this change in rate design. On April 19, 2007, the FERC issued an order rejecting the ALJ’s findings and recommendations in nearly every respect. FERC found that the PJM transmission owners’ existing “license plate” rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be socialized throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. Nevertheless, FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.

FERC’s orders on PJM rate design, if sustained on rehearing and appeal, will prevent the allocation of the cost of existing transmission facilities of other utilities to JCP&L, Met-Ed, and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce future transmission costs shifting to the JCP&L, Met-Ed and Penelec zones.

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 with an implementation in the second or third quarter of 2008. FirstEnergy filed comments on March 23, 2007, supporting the ancillary service market in concept, but proposing certain changes in MISO’s proposal. MISO has requested FERC action on its filing by June 2007.

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. MISO, PJM and ATSI will be filing revised tariffs to comply with FERC’s order.

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, the 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 and SFAS 107. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. FirstEnergy 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. FirstEnergy is currently evaluating the impact of this Statement on its financial statements.

EITF 06-10 - “Accounting for Deferred Compensation and Postretirement Benefit Aspects of Collateral

Split-Dollar Life Insurance Arrangements”

In March 2007, the EITF reached a final consensus on Issue 06-10 concluding that an employer should recognize a liability for the postretirement obligation associated with a collateral assignment split-dollar life insurance arrangement if, based on the substantive arrangement with the employee, the employer has agreed to maintain a life insurance policy during the employee’s retirement or provide the employee with a death benefit. The liability should be recognized in accordance with SFAS 106 if, in substance, a postretirement plan exists or APB 12 if the arrangement is, in substance, an individual deferred compensation contract. The EITF also reached a consensus that the employer should recognize and measure the associated asset on the basis of the terms of the collateral assignment arrangement. This pronouncement is effective for fiscal years beginning after December 15, 2007, including interim periods within those years. FirstEnergy does not expect this pronouncement to have a material impact on its financial statements.

12. SEGMENT INFORMATION

Effective January 1, 2007, FirstEnergy has three reportable operating segments: competitive energy services, energy delivery services and Ohio transitional generation services. None of the aggregate “Other” segments individually meet the criteria to be considered a reportable segment. The competitive energy services segment primarily consists of unregulated generation and commodity operations, including competitive electric sales, and generation sales to affiliated electric utilities. The energy delivery services segment consists of regulated transmission and distribution operations, including transition cost recovery, and PLR generation service for FirstEnergy’s Pennsylvania and New Jersey electric utility subsidiaries. The Ohio transitional generation services segment represents PLR generation service by FirstEnergy’s Ohio electric utility subsidiaries. “Other” primarily consists of telecommunications services and other non-core assets. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable operating segments.”

The energy delivery services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems and is responsible for the regulated generation commodity operations of FirstEnergy’s Pennsylvania and New Jersey electric utility subsidiaries. Its revenues are primarily derived from the delivery of electricity, cost recovery of regulatory assets and PLR electric generation sales to non-shopping customers in its Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES under partial requirements purchased power agreements and non-affiliated power suppliers as well as the net PJM transmission expenses related to the delivery of that generation load.

The competitive energy services segment supplies electric power to its electric utility affiliates, provides competitive electric sales primarily in Ohio, Pennsylvania, Maryland and Michigan and owns and operates FirstEnergy’s generating facilities and purchases electricity to meet its sales obligations. The segment's net income is primarily derived from the affiliated company power sales and the non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO to deliver electricity to the segment’s customers. The segment’s internal revenues represent the affiliated company power sales.

The Ohio transitional generation services segment represents the regulated generation commodity operations of FirstEnergy’s Ohio electric utility subsidiaries. Its revenues are primarily derived from electric generation sales to non-shopping customers under the PLR obligations of the Ohio Companies. Its results reflect securing electric generation from the competitive energy services segment through full requirements PSA arrangements and the net MISO transmission revenues and expenses related to the delivery of that generation load.

Segment reporting in 2006 has been revised to conform to the current year business segment organization and operations. Changes in the current year operations reporting reflected in the revised 2006 segment reporting primarily reflects the transfer within FirstEnergy’s management and organization of the responsibility of obtaining PLR generation for the utilities for their non-shopping customers from FES to business units within the regulated utilities. This reflects FirstEnergy’s alignment of its business units to accommodate its retail strategy and participation in competitive electricity marketplaces in Ohio, Pennsylvania and New Jersey. The differentiation of the regulated generation commodity operations between the two regulated business segments recognizes that generation sourcing for the Ohio Companies is currently in a transitional state through 2008 as compared to the segregated commodity sourcing of their Pennsylvania and New Jersey utility affiliates. The results of the energy delivery services and the Ohio transitional generation services segments now include their electric generation revenues and the corresponding generation commodity costs under affiliated and non-affiliated purchased power arrangements and related net retail PJM/MISO transmission expenses associated with serving electricity load in their respective franchise areas.

FSG completed the sale of its five remaining subsidiaries in 2006. Its assets and results for 2006 are combined in the “Other” segments in this report, as the remaining business does not meet the criteria of a reportable segment. Interest expense on holding company debt and corporate support services revenues and expenses are included in "Reconciling Items."

Segment Financial Information
					Ohio
	Energy		Competitive		Transitional
	Delivery		Energy		Generation						Reconciling
Three Months Ended	Services		Services		Services			Other			Adjustments			Consolidated
	(In millions)
March 31, 2007
External revenues	$	2,040	$	328	$	619		$	12		$	(26	)	$	2,973
Internal revenues		-		714		-			-			(714	)		-
Total revenues		2,040		1,042		619			12			(740	)		2,973
Depreciation and amortization		220		51		(15	)		1			6			263
Investment income		70		3		1			-			(41	)		33
Net interest charges		107		49		1			2			21			180
Income taxes		148		65		15			5			(33	)		200
Net income		218		98		24			1			(51	)		290
Total assets		23,526		7,089		246			254			675			31,790
Total goodwill		5,874		24		-			-			-			5,898
Property additions		155		124		-			1			16			296

March 31, 2006
External revenues	$	1,796	$	355	$	543		$	28		$	(17	)	$	2,705
Internal revenues		9		611		-			-			(620	)		-
Total revenues		1,805		966		543			28			(637	)		2,705
Depreciation and amortization		258		46		(21	)		1			5			289
Investment income		84		15		-			-			(56	)		43
Net interest charges		99		44		-			1			16			160
Income taxes		126		21		20			(6	)		(26	)		135
Income from
continuing operations		189		32		30			12			(44	)		219
Discontinued operations		-		-		-			2			-			2
Net income		189		32		30			14			(44	)		221
Total assets		23,633		6,759		215			367			823			31,797
Total goodwill		5,916		24		-			-			-			5,940
Property additions		193		244		-			-			10			447

Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting primarily consist of interest expense related to holding company debt, corporate support services revenues and expenses, fuel marketing revenues (which are reflected as reductions to expenses for internal management reporting purposes) and elimination of intersegment transactions.

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

	Three Months Ended
	March 31,
	2007			2006
	*(In millions, except per share amounts)*
REVENUES:
Electric utilities	$	2,681		$	2,340
Unregulated businesses		292			365
Total revenues*		2,973			2,705

EXPENSES:
Fuel and purchased power		1,121			998
Other operating expenses		749			754
Provision for depreciation		156			148
Amortization of regulatory assets		251			221
Deferral of new regulatory assets		(144	)		(80	)
General taxes		203			193
Total expenses		2,336			2,234

OPERATING INCOME		637			471

OTHER INCOME (EXPENSE):
Investment income		33			43
Interest expense		(185	)		(165	)
Capitalized interest		5			7
Subsidiaries’ preferred stock dividends		-			(2	)
Total other expense		(147	)		(117	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		490			354

INCOME TAXES		200			135

INCOME FROM CONTINUING OPERATIONS		290			219

Discontinued operations (net of income tax benefit of $1 million)
(Note 3)		-			2

NET INCOME	$	290		$	221

BASIC EARNINGS PER SHARE OF COMMON STOCK:
Income from continuing operations	$	0.92		$	0.67
Discontinued operations (Note 3)		-			-
Net income	$	0.92		$	0.67

WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING		314			329

DILUTED EARNINGS PER SHARE OF COMMON STOCK:
Income from continuing operations	$	0.92		$	0.67
Discontinued operations (Note 3)		-			-
Net income	$	0.92		$	0.67

WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING		316			330

DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	0.50		$	0.45


* Includes $104 million and $99 million of excise tax collections in the first quarter of 2007 and 2006, respectively.

The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,
	2007			2006
	*(In millions)*

NET INCOME	$	290		$	221

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(11	)		-
Unrealized gain on derivative hedges		21			37
Unrealized gain on available for sale securities		17			37
Other comprehensive income		27			74
Income tax expense related to other comprehensive income		9			27
Other comprehensive income, net of tax		18			47

COMPREHENSIVE INCOME	$	308		$	268


The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.

FIRSTENERGY CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2007			2006
	*(In millions)*
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	89		$	90
Receivables-
Customers (less accumulated provisions of $40 million and
$43 million, respectively, for uncollectible accounts)		1,250			1,135
Other (less accumulated provisions of $23 million and
$24 million, respectively, for uncollectible accounts)		184			132
Materials and supplies, at average cost		591			577
Prepayments and other		233			149
		2,347			2,083
PROPERTY, PLANT AND EQUIPMENT:
In service		24,223			24,105
Less - Accumulated provision for depreciation		10,191			10,055
		14,032			14,050
Construction work in progress		754			617
		14,786			14,667
INVESTMENTS:
Nuclear plant decommissioning trusts		2,008			1,977
Investments in lease obligation bonds		775			811
Other		742			746
		3,525			3,534
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		5,898			5,898
Regulatory assets		4,371			4,441
Pension assets		277			-
Other		586			573
		11,132			10,912
	$	31,790		$	31,196
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt	$	2,093		$	1,867
Short-term borrowings		2,247			1,108
Accounts payable		625			726
Accrued taxes		413			598
Other		1,020			956
		6,398			5,255
CAPITALIZATION:
Common stockholders’ equity-
Common stock, $.10 par value, authorized 375,000,000 shares-
304,835,407 and 319,205,517 shares outstanding, respectively		30			32
Other paid-in capital		5,574			6,466
Accumulated other comprehensive loss		(241	)		(259	)
Retained earnings		2,941			2,806
Unallocated employee stock ownership plan common stock-
324,738 and 521,818 shares, respectively		(5	)		(10	)
Total common stockholders' equity		8,299			9,035
Long-term debt and other long-term obligations		8,546			8,535
		16,845			17,570
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		2,826			2,740
Asset retirement obligations		1,208			1,190
Power purchase contract loss liability		1,063			1,182
Retirement benefits		920			944
Lease market valuation liability		745			767
Other		1,785			1,548
		8,547			8,371
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
	$	31,790		$	31,196

The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these balance sheets.

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31,
	2007			2006
	*(In millions)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	290		$	221
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		156			148
Amortization of regulatory assets		251			222
Deferral of new regulatory assets		(144	)		(80	)
Nuclear fuel and lease amortization		26			20
Deferred purchased power and other costs		(116	)		(104	)
Deferred income taxes and investment tax credits, net		53			6
Investment impairment		5			-
Deferred rents and lease market valuation liability		(25	)		(38	)
Accrued compensation and retirement benefits		(65	)		(19	)
Commodity derivative transactions, net		1			26
Income from discontinued operations		-			(2	)
Cash collateral		6			(106	)
Pension trust contribution		(300	)		-
Decrease (Increase) in operating assets-
Receivables		(155	)		226
Materials and supplies		15			(52	)
Prepayments and other current assets		(74	)		(93	)
Increase (Decrease) in operating liabilities-
Accounts payable		(108	)		(114	)
Accrued taxes		73			9
Accrued interest		86			100
Electric service prepayment programs		(17	)		(14	)
Other		(33	)		(32	)
Net cash provided from (used for) operating activities		(75	)		324

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		250			-
Short-term borrowings, net		1,139			200
Redemptions and Repayments-
Common stock		(891	)		-
Preferred stock		-			(30	)
Long-term debt		(13	)		(64	)
Net controlled disbursement activity		12			(8	)
Stock-based compensation tax benefit		8			-
Common stock dividend payments		(159	)		(148	)
Net cash provided from (used for) financing activities		346			(50	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(296	)		(447	)
Proceeds from asset sales		-			57
Proceeds from nuclear decommissioning trust fund sales		266			481
Investments in nuclear decommissioning trust funds		(269	)		(484	)
Cash investments		25			103
Other		2			(20	)
Net cash used for investing activities		(272	)		(310	)

Net decrease in cash and cash equivalents		(1	)		(36	)
Cash and cash equivalents at beginning of period		90			64
Cash and cash equivalents at end of period	$	89		$	28


The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of FirstEnergy Corp.:

We have reviewed the accompanying consolidated balance sheets of FirstEnergy Corp. and its subsidiaries as of March 31, 2007 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholders’ equity, preferred stock and cash flows for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006; and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(K) and Note 12 to the consolidated financial statements) dated February 27, 2007, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 8, 2007

FIRSTENERGY CORP.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EXECUTIVE SUMMARY

Net income in the first quarter of 2007 was $290 million, or basic and diluted earnings of $0.92 per share of common stock, compared with net income of $221 million, or basic and diluted earnings of $0.67 per share in the first quarter of 2006. The increase in FirstEnergy’s earnings was driven primarily by increased electric sales revenues, partially offset by higher fuel and purchase power costs.

Change in Basic Earnings Per Share From Prior Year First Quarter

Basic Earnings Per Share - First Quarter 2006		$ 0.67
Revenues		0.51
Fuel and purchased power		(0.24)
Depreciation and amortization		(0.08)
Deferral of new regulatory assets		0.07
Other expenses		(0.05)
Saxton decommissioning regulatory asset		0.05
Trust securities impairment		(0.01)
Basic Earnings Per Share - First Quarter 2007		$ 0.92

Financial Matters

Share Repurchase Programs - On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding common stock under an accelerated share repurchase (ASR) agreement with an affiliate of Morgan Stanley & Co. Incorporated. The initial purchase price was approximately $900 million, or $62.63 per share. The final purchase price for this program will be adjusted to reflect the volume weighted average price of FirstEnergy’s common stock during the period of time that the bank will acquire shares to cover its short position, which is approximately one year. The ASR was completed under a January 30, 2007 Board of Directors authorization to repurchase up to 16 million shares of outstanding common stock.

On April 2, 2007, an affiliate of J.P. Morgan Securities completed its acquisition of shares under FirstEnergy’s prior ASR program of 10.6 million shares, which was executed in August 2006. In settling the transaction, FirstEnergy remitted approximately $27 million to J.P. Morgan as a final purchase price adjustment based on the average of the daily volume-weighted average price over the purchase period, as well as other purchase price adjustments.

Under the two ASR programs, FirstEnergy has repurchased approximately 25 million shares, or 8%, of the total shares outstanding as of July 2006.

Sale and Leaseback of Bruce Mansfield Unit 1 - On January 31, 2007, FirstEnergy announced its intention to pursue a sale and leaseback transaction for its owned portion (776 MW) of Bruce Mansfield Unit 1. FirstEnergy anticipates the after-tax proceeds of this proposed transaction to be approximately $1.2 billion. The proceeds are expected to be used to repay short-term borrowings incurred to fund the recently executed ASR program and the recent voluntary pension plan contribution. FirstEnergy is targeting a second quarter of 2007 closing for the transaction including related lease debt financing.

New Long-Term Debt Issuance - On March 27, 2007, CEI issued $250 million of 5.70% unsecured senior notes due 2017. The proceeds from the transaction were used to repay short-term borrowings and for general corporate purposes.

Credit Rating Agency Update - On March 26, 2007, S&P assigned its corporate credit rating of BBB to FES. Moody’s also issued a rating of Baa2 on FES on March 27, 2007. FES is the holding company of FirstEnergy Generation Corp. and FirstEnergy Nuclear Generation Corp., the owners of FirstEnergy’s fossil and nuclear generation assets, respectively. Both S&P and Moody’s cited the strength of FirstEnergy’s generation portfolio as a key contributor to the investment grade credit ratings.

Regulatory Matters

Ohio - On August 31, 2005, the PUCO approved a rider recovery mechanism through which the Ohio Companies may recover all MISO transmission and ancillary service related costs incurred during each year ending June 30. Pursuant to the PUCO’s order, the Ohio Companies, on May 1, 2007, filed revised riders which will automatically become effective on July 1, 2007. The revised riders represent an increase over the amounts collected through the 2006 riders of approximately $64 million annually.

Pennsylvania - On January 11, 2007, the PPUC issued its order in the Met-Ed and Penelec 2006 comprehensive transition rate cases (see Note 10). Several parties to the proceeding, including Met-Ed and Penelec, have filed appeals with the Pennsylvania Commonwealth Court, which are currently pending.

A hearing was held February 21, 2007 in the Met-Ed and Penelec NUG accounting case. In this case, Met-Ed and Penelec are seeking to modify the NUG purchased power stranded costs accounting methodology to eliminate improper reductions of the deferred cost balance during periods in which market prices exceed NUG payments. The ALJ’s initial decision was issued on May 3, 2007 and denied Met-Ed's and Penelec’s request to modify their NUG stranded cost accounting methodology. The companies may file exceptions to the initial decision by May 22, 2007 and parties may reply to those exceptions 10 days thereafter. It is not known when the PPUC may issue a final decision in this matter.

On May 2, 2007, Penn made a filing with the PPUC proposing how it will procure the power supply needed for default service customers beginning June 1, 2008. Penn’s customers transitioned to a fully competitive market on January 1, 2007, and the default service plan that the PPUC previously approved covered a 17-month period through May 31, 2008. The filing proposes that Penn procure a full requirements product, by class, through multiple RFPs with staggered delivery periods extending through May 2011. It also proposes a 3-year phase-out of promotional generation rates. Penn expects the PPUC to address the filing later this year.

Generation

NRC Oversight Update - On March 2, 2007, the NRC returned FirstEnergy’s Perry Plant to routine agency oversight as a result of sufficient corrective actions that have been taken over the last two-and-one-half years. The Perry Plant had been operating under heightened NRC oversight since August 2004 (see Note 9).

Refueling Outage - FirstEnergy’s Perry Plant began its regularly scheduled refueling outage on April 2, 2007. Major work activities to be completed on the 1,258 MW facility include replacing approximately one-third of the fuel assemblies in the reactor and two of the three low-pressure turbine rotors in the main generator.

Power Uprates - In March 2007, Beaver Valley Unit 1 completed the final phase of an extended power uprate project to add additional capacity to FirstEnergy’s system. This is its second power uprate in the past 12 months. Capacity testing will be conducted later this year to verify the actual megawatts gained. This power uprate was achieved in support of FirstEnergy’s strategy to maximize the full potential of its existing generation assets.

Environmental Update - In March 2007, an SNCR system was placed in-service at FirstEnergy’s 597 MW Eastlake Unit 5, upon completion of a scheduled maintenance outage. The SNCR installation is part of FirstEnergy’s overall Air Quality Compliance Strategy and was required under the New Source Review consent decree. The SNCR is expected to reduce NOx emissions and help achieve reductions required by the EPA’s NOx Transport Rule.

FIRSTENERGY’S BUSINESS

FirstEnergy is a public utility holding company headquartered in Akron, Ohio, that operates primarily through three core business segments (see Results of Operations).

Energy Delivery Services transmits and distributes electricity through FirstEnergy's eight utility operating companies, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey and purchases power for its PLR requirements in Pennsylvania and New Jersey. This business segment derives its revenues principally from the delivery of electricity within FirstEnergy’s service areas, cost recovery of regulatory assets and the sale of electric generation to non-shopping retail customers under the PLR obligations in its Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from the Competitive Energy Services Segment under partial requirements purchased power agreements with FES and non-affiliated power suppliers as well as the net PJM transmission expenses related to the delivery of that generation load.

Competitive Energy Services supplies the electric power needs of end-use customers through retail and wholesale arrangements, including associated company power sales to meet all or a portion of the PLR requirements of FirstEnergy's Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland and Michigan. This business segment owns and operates FirstEnergy's generating facilities and also purchases electricity to meet sales obligations. The segment's net income is primarily derived from the affiliated company power sales and the non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO to deliver energy to the segment’s customers.

Ohio Transitional Generation Services supplies the electric power needs of non-shopping customers under the PLR requirements of FirstEnergy's Ohio Companies. The segment's net income is primarily derived from electric generation sales revenues less the cost of power purchased from the competitive energy services segment through a full-requirements PSA arrangement with FES and net transmission (including congestion) and ancillary costs charged by MISO to deliver energy to its retail customers.

RESULTS OF OPERATIONS

The financial results discussed below include revenues and expenses from transactions among FirstEnergy's business segments. A reconciliation of segment financial results is provided in Note 12 to the consolidated financial statements. Net income by major business segment was as follows:

	Three Months Ended
	March 31,						Increase
	2007			2006			(Decrease)
Net Income	*(In millions, except per share data)*
By Business Segment
Energy delivery services	$	218		$	189		$	29
Competitive energy services		98			32			66
Ohio transitional generation services		24			30			(6	)
Other and reconciling adjustments*		(50	)		(30	)		(20	)
Total	$	290		$	221		$	69

Basic and Diluted Earnings Per Share	$	0.92		$	0.67		$	0.25

*Represents other operating segments and reconciling items including interest expense on holding company debt and

corporate support services revenues and expenses.

Net income in the first quarter of 2006 included after-tax earnings from discontinued operations of $2 million resulting from FirstEnergy’s disposition of non-core assets and operations (see Note 3).

Financial results for FirstEnergy's major business segments in the first quarter of 2007 and 2006 were as follows:

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
First Quarter 2007 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	1,875		$	276		$	613		$	-		$	2,764
Other		165			52			6			(14	)		209
Internal		-			714			-			(714	)		-
Total Revenues		2,040			1,042			619			(728	)		2,973

Expenses:
Fuel and purchased power		844			447			544			(714	)		1,121
Other operating expenses		408			307			49			(15	)		749
Provision for depreciation		98			51			-			7			156
Amortization of regulatory assets		246			-			5			-			251
Deferral of new regulatory assets		(124	)		-			(20	)		-			(144	)
General taxes		165			28			2			8			203
Total Expenses		1,637			833			580			(714	)		2,336

Operating Income		403			209			39			(14	)		637
Other Income (Expense):
Investment income		70			3			1			(41	)		33
Interest expense		(109	)		(52	)		(1	)		(23	)		(185	)
Capitalized interest		2			3			-			-			5
Total Other Expense		(37	)		(46	)		-			(64	)		(147	)

Income From Continuing Operations Before
Income Taxes		366			163			39			(78	)		490
Income taxes		148			65			15			(28	)		200
Net Income	$	218		$	98		$	24		$	(50	)	$	290

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
First Quarter 2006 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	1,668		$	304		$	539		$	-		$	2,511
Other		128			51			4			11			194
Internal		9			611			-			(620	)		-
Total Revenues		1,805			966			543			(609	)		2,705

Expenses:
Fuel and purchased power		693			468			457			(620	)		998
Other operating expenses		366			344			56			(12	)		754
Provision for depreciation		96			46			-			6			148
Amortization of regulatory assets		217			-			4			-			221
Deferral of new regulatory assets		(55	)		-			(25	)		-			(80	)
General taxes		158			26			1			8			193
Total Expenses		1,475			884			493			(618	)		2,234

Operating Income		330			82			50			9			471
Other Income (Expense):
Investment income		84			15			-			(56	)		43
Interest expense		(100	)		(47	)		-			(18	)		(165	)
Capitalized interest		3			3			-			1			7
Subsidiaries' preferred stock dividends		(2	)		-			-			-			(2	)
Total Other Expense		(15	)		(29	)		-			(73	)		(117	)

Income From Continuing Operations Before
Income Taxes		315			53			50			(64	)		354
Income taxes		126			21			20			(32	)		135
Income from continuing operations		189			32			30			(32	)		219
Discontinued operations		-			-			-			2			2
Net Income	$	189		$	32		$	30		$	(30	)	$	221


Changes Between First Quarter 2007 and
First Quarter 2006 Financial Results
Increase (Decrease)

Revenues:
External
Electric	$	207		$	(28	)	$	74		$	-		$	253
Other		37			1			2			(25	)		15
Internal		(9	)		103			-			(94	)		-
Total Revenues		235			76			76			(119	)		268

Expenses:
Fuel and purchased power		151			(21	)		87			(94	)		123
Other operating expenses		42			(37	)		(7	)		(3	)		(5	)
Provision for depreciation		2			5			-			1			8
Amortization of regulatory asset		29			-			1			-			30
Deferral of new regulatory assets		(69	)		-			5			-			(64	)
General taxes		7			2			1			-			10
Total Expenses		162			(51	)		87			(96	)		102

Operating Income		73			127			(11	)		(23	)		166
Other Income (Expense):
Investment income		(14	)		(12	)		1			15			(10	)
Interest expense		(9	)		(5	)		(1	)		(5	)		(20	)
Capitalized interest		(1	)		-			-			(1	)		(2	)
Subsidiaries' preferred stock dividends		2			-			-			-			2
Total Other Income (Expense)		(22	)		(17	)		-			9			(30	)

Income From Continuing Operations Before
Income Taxes		51			110			(11	)		(14	)		136
Income taxes		22			44			(5	)		4			65
Income from continuing operations		29			66			(6	)		(18	)		71
Discontinued operations		-			-			-			(2	)		(2	)
Net Income	$	29		$	66		$	(6	)	$	(20	)	$	69

Energy Delivery Services - First Quarter 2007 Compared to First Quarter 2006

Net income increased $29 million (or 15%) to $218 million in the first quarter of 2007 compared to $189 million in the first quarter of 2006, primarily due to increased revenues partially offset by higher operating expenses and lower investment income.

Revenues -

The increase in total revenues resulted from the following sources:

	Three Months Ended
	March 31,				Increase
Revenues By Type of Service	2007		2006		(Decrease)
	*(In millions)*
Distribution services	$	944	$	935	$	9
Generation sales:
Retail		720		637		83
Wholesale		132		55		77
Total generation sales		852		692		160
Transmission		183		124		59
Other		61		54		7
Total Revenues	$	2,040	$	1,805	$	235

The increases in distribution deliveries by customer class are summarized in the following table:

Electric Distribution Deliveries
Residential	7.1	%
Commercial	4.3	%
Industrial	0.1	%
Total Distribution Deliveries	3.9	%

The increase in electric distribution deliveries to customers was primarily due to colder than average weather during the first quarter of 2007 compared to unseasonably mild weather during the same period of 2006, offset by an unfavorable rate mix and distribution rate decreases for Met-Ed and Penelec as a result of a January 11, 2007 PPUC rate decision (see Outlook - State Regulatory Matters - Pennsylvania).

The following table summarizes the price and volume factors contributing to the $160 million increase in non-affiliated generation sales in 2007 compared to 2006:

Sources of Change in Generation Sales	Increase
	*(In millions)*
Retail:
Effect of 0.3% increase in volume	$	2
Change in prices		81
		83
Wholesale:
Effect of 139% increase in volume		77
Change in prices		-
		77
Net Increase in Generation Sales	$	160

The increase in retail generation prices during the first quarter of 2007 compared to 2006 was primarily due to increased generation and NUGC rates for JCP&L resulting from the New Jersey BGS auction. Wholesale generation sales increased principally as a result of Met-Ed and Penelec selling additional available power into the PJM market beginning in January 2007.

The $59 million increase in transmission revenue was primarily due to approximately $42 million of Met-Ed and Penelec transmission revenues in 2007 resulting from a January 2007 PPUC authorization for transmission costs recovery. Met-Ed and Penelec defer the difference between revenues accrued under the transmission rider and transmission costs incurred, with no material effect to current period earnings.

Expenses -

The net increases in revenues discussed above were partially offset by a $162 million increase in expenses due to the following:

Purchased power costs were $151 million higher in the first quarter of 2007 due to higher unit prices and volumes purchased. The increased unit prices reflected the effect of higher JCP&L purchased power unit prices resulting from the BGS auction. The increased KWH purchases in 2007 were due in part to higher customer usage and sales to the wholesale market. The following table summarizes the sources of changes in purchased power costs:

Sources of Change in Purchased Power	Increase (Decrease)
	*(In millions)*

Purchased Power:
Change due to increased unit costs	$	74
Change due to increased volume		79
Decrease in NUG costs deferred		(2	)
Net Increase in Purchased Power Costs	$	151

Other operating expenses increased $42 million due to the net effects of:

-	An increase of $52 million in MISO and PJM transmission expenses, resulting primarily from higher congestion costs;

-	Miscellaneous operating expenses decreased $8 million primarily due to reduced support services billings from FESC; and

-	Operation and maintenance expenses decreased $2 million primarily due to lower employee benefit and storm-related costs.

Amortization of regulatory assets increased $29 million compared to 2006 due primarily to recovery of deferred BGS costs through higher NUGC revenues for JCP&L as discussed above;

The deferral of new regulatory assets during the first quarter of 2007 was $69 million higher in 2007 primarily due to the deferral of previously expensed decommissioning expenses of $27 million related to the Saxton nuclear research facility (see Outlook - State Regulatory Matters - Pennsylvania) and the absence in the first quarter of 2006 of PJM transmission costs and interest deferrals of $33 million that began during the second quarter of 2006.

Other Income and Expense -

Other income decreased $22 million in 2007 compared to the first quarter of 2006 primarily due to lower interest income of $14 million from repayment of associated company notes receivable since the first quarter of 2006 related to the generation asset transfers and increased interest expense of $9 million related in part to new debt issuances by CEI and JCP&L.

Ohio Transitional Generation Services - First Quarter 2007 Compared to First Quarter 2006

Net income for this segment decreased to $24 million in the first quarter of 2007 from $30 million in the same period last year. Higher generation revenues were more than offset by higher operating expenses, primarily for purchased power.

Revenues -

The increase in reported segment revenues resulted from the following sources:

	Three Months Ended
	March 31,				Increase
Revenues By Type of Service	2007		2006		(Decrease)
	*(In millions)*
Generation sales:
Retail	$	545	$	472	$	73
Wholesale		2		7		(5	)
Total generation sales		547		479		68
Transmission		71		63		8
Other		1		1		-
Total Revenues	$	619	$	543	$	76

The following table summarizes the price and volume factors contributing to the increase in sales revenues from retail customers:

Source of Change in Electric Generation Sales	Increase
	*(In millions)*
Retail:
Effect of 6.6% increase in customer usage	$	31
Change in prices		42
Total Increase in Retail Generation Sales	$	73

The customer usage increase was due to colder weather in the first quarter of 2007 compared to the same period of 2006 and reduced customer shopping. Average prices increased primarily due to higher composite unit prices for returning customers. The percentage of generation services provided by alternative suppliers to total sales delivered in the Ohio Companies’ service areas decreased by a weighted average of 2.1 percentage points.

Expenses -

Purchased power costs were $87 million higher due primarily to higher unit prices for power purchased from FES. The factors contributing to the higher costs are summarized in the following table:

Source of Change in Purchased Power	Increase
	*(In millions)*
Purchases from non-affiliates:
Change due to increased unit costs	$	10
Change due to volume purchased		-
		10
Purchases from FES:
Change due to increased unit costs		55
Change due to volume purchased		22
		77
Total Increase in Purchased Power Costs	$	87

The increase in KWH purchases was due to the higher retail generation sales requirements. The higher unit costs resulted from the provision of the full-requirements PSA with FES under which purchased power unit costs reflected the increases in the Ohio Companies’ retail generation sales unit prices.

Competitive Energy Services - First Quarter 2007 Compared to First Quarter 2006

Net income for this segment was $98 million in the first quarter of 2007 compared to $32 million in the same period last year. An improvement in gross generation margin and lower other operating expenses was partially offset by higher general taxes and reduced investment income.

Revenues -

Total revenues increased $76 million in the first quarter of 2007 compared to the same period in 2006. This increase primarily resulted from higher unit prices under affiliated power sales to the Ohio companies which was partially offset by lower non-affiliated wholesale sales.

The higher retail revenues resulted from increased sales in both the MISO and PJM markets. Lower non-affiliated wholesale revenues reflected the effect of decreased generation available for the non-affiliated wholesale market due to increased affiliated company power sales requirements under the Ohio Companies’ full-requirements PSA and the partial-requirements power sales agreement with Met-Ed and Penelec.

The increased affiliated company generation revenues were due to higher unit prices and increased KWH sales. Factors contributing to the revenue increase from PSA sales to the Ohio Companies are discussed under the purchased power costs analysis in the Ohio Transitional Generation Services results above. The higher KWH sales to the Pennsylvania affiliates were due to increased Met-Ed and Penelec generation sales requirements. These increases were partially offset by decreased sales to Penn as a result of the implementation of its competitive solicitation process in the first quarter of 2007.

The increase in reported segment revenues resulted from the following sources:

	Three Months Ended
	March 31,				Increase
Revenues By Type of Service	2007		2006		(Decrease)
	*(In millions)*
Non-Affiliated Generation Sales:
Retail	$	173	$	131	$	42
Wholesale		103		173		(70	)
Total Non-Affiliated Generation Sales		276		304		(28	)
Affiliated Power Sales		714		611		103
Transmission		23		20		3
Other		29		31		(2	)
Total Revenues	$	1,042	$	966	$	76

The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:

	Increase
Source of Change in Non-Affiliated Generation Sales	(Decrease)
	*(In millions)*
Retail:
Effect of 17.9% increase in customer usage	$	23
Change in prices		19
		42
Wholesale:
Effect of 35.9% decrease in KWH sales		(62	)
Change in prices		(8	)
		(70	)
Net Decrease in Non-Affiliated Generation Sales	$	(28	)


Source of Change in Affiliated Generation Sales	Increase
	*(In millions)*
Ohio Companies:
Effect of 4.9% increase in KWH sales	$	22
Change in prices		55
		77
Pennsylvania Companies:
Effect of 10.0% increase in KWH sales		16
Change in prices		10
		26
Net Increase in Affiliated Generation Sales	$	103

Expenses -

Total operating expenses were $51 million lower in the first quarter of 2007 due to the following factors:

	Increase
Source of Change in Fuel and Purchased Power	(Decrease)
	*(In millions)*
Fuel:
Change due to decreased composite unit costs	$	(11	)
Change due to volume consumed		(9	)
		(20	)
Purchased Power:
Change due to decreased unit costs		(30	)
Change due to volume purchased		29
		(1	)
Net Decrease in Fuel and Purchased Power Costs	$	(21	)

Fuel costs were $20 million lower primarily due to reduced coal costs ($19 million) and lower emission allowance costs ($6 million) reflecting decreased fossil KWH production, partially offset by a $7 million increase in nuclear fuel costs resulting from higher nuclear KWH production;

Purchased power costs decreased by $1 million due primarily to lower unit costs for power in MISO and lower KWH purchases in PJM, partially offset by higher unit prices in PJM; and

Other operating expenses were $37 million lower in 2007 primarily due to the absence of contractor service costs related to the 2006 refueling outages at Beaver Valley Unit 1 and Davis-Besse with no refueling outages in the first quarter of 2007.

Partially offsetting the lower costs were the following:

Higher fossil plant operating costs principally due to planned maintenance outages at Sammis Units 6 and 7 and Eastlake Unit 5; and

Increased depreciation expense of $5 million resulting principally from fossil and nuclear property additions since the first quarter of 2006.

Other Income -

Investment income in the first quarter of 2007 was $17 million lower than the 2006 period primarily due to decreased earnings on nuclear decommissioning trust investments.

Other - First Quarter 2007 Compared to First Quarter 2006

FirstEnergy’s financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $20 million decrease in FirstEnergy’s net income in the first quarter of 2007 compared to the same quarter of 2006. The decrease was due to higher short-term disability costs ($8 million), the absence of $2 million included in 2006 results from discontinued operations (see Note 3) and a $3 million gain in 2006 related to interest rate swap financing arrangements. In addition, there was a $3 million decrease in life insurance investment income and increased interest expense in 2007 compared to 2006 due to higher revolving credit facility borrowings and a new $250 million bridge loan in March 2007.

CAPITAL RESOURCES AND LIQUIDITY

FirstEnergy’s business is capital intensive and requires considerable capital resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. In 2007 and subsequent years, FirstEnergy expects to meet its contractual obligations and other cash requirements primarily with a combination of cash from operations and funds from the capital markets. FirstEnergy also expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.

Changes in Cash Position

FirstEnergy's primary source of cash required for continuing operations as a holding company is cash from the operations of its subsidiaries. FirstEnergy also has access to $2.75 billion of short-term financing under a revolving credit facility which expires in 2011, subject to short-term debt limitations under current regulatory approvals of $1.5 billion and to outstanding borrowings by its subsidiaries that are also parties to such facility. In the first quarter of 2007, FirstEnergy received $160 million of cash dividends and return of capital contributions from its subsidiaries and paid $159 million in cash dividends to common shareholders. With the exception of Met-Ed, which is currently in an accumulated deficit position, there are no material restrictions on the payment of cash dividends by the subsidiaries of FirstEnergy.

On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or approximately 4.5%, of its outstanding common stock at an initial price of approximately $900 million, pursuant to an accelerated share repurchase. FirstEnergy acquired these shares under its previously announced authorization to repurchase up to 16 million shares of its common stock. Under a prior authorized program, FirstEnergy repurchased approximately 10.6 million of its outstanding common stock on August 10, 2006, under an accelerated share repurchase agreement, dated August 9, 2006. The latest share repurchase was funded with short-term borrowings, including $500 million from bridge loan facilities.

As of March 31, 2007, FirstEnergy had $89 million of cash and cash equivalents compared with $90 million as of December 31, 2006. The major sources of changes in these balances are summarized below.

Cash Flows From Operating Activities

FirstEnergy's consolidated net cash from operating activities is provided primarily by its energy delivery and competitive energy businesses (see Results of Operations above). Net cash used for operating activities was $75 million in the first quarter of 2007 compared to $324 million provided from operating activities in the first quarter of 2006, as summarized in the following table:

	Three Months Ended
	March 31,
Operating Cash Flows	2007			2006
	*(In millions)*
Net income	$	290		$	221
Non-cash charges		125			165
Pension trust contribution		(300	)		-
Working capital and other		(190	)		(62	)
Net cash provided from (used for) operating activities	$	(75	)	$	324

Net cash provided from operating activities decreased by $399 million in the first quarter of 2007 compared to the first quarter of 2006 primarily due to a $300 million pension trust contribution in 2007 and $168 million from decreases in working capital and non-cash charges, partially offset by a $69 million increase in net income described under “Results of Operations.” The decrease from working capital and other changes primarily resulted from a $381 million decrease in cash provided from the collection of receivables, partially offset by increased cash collateral of $112 million returned from suppliers and $66 million from income tax refunds received during the 2007 period.

Cash Flows From Financing Activities

In the first quarter of 2007, net cash provided from financing activities was $346 million compared to $50 million used for financing activities in the first quarter of 2006. The change was primarily due to a long-term debt issuance in 2007 and higher short-term borrowings, partially offset by the repurchase of common stock

	Three Months Ended
	March 31,
Securities Issued or Redeemed	2007		2006
	*(In millions)*
New Issues:
Unsecured notes	$	250	$	-

Redemptions:
Pollution control notes	$	-	$	54
Senior secured notes		13		10
Common stock		891		-
Preferred stock		-		30
	$	904	$	94

Short-term borrowings, net	$	1,139	$	200

FirstEnergy had approximately $2.2 billion of short-term indebtedness as of March 31, 2007 compared to approximately $1.1 billion as of December 31, 2006. The increase was primarily due to the voluntary pension fund contribution and the common share repurchase program in the first quarter of 2007. Available bank borrowing capability as of March 31, 2007 included the following:

Borrowing Capability (In millions)
Short-term credit facilities⁽¹⁾	$	3,370
Accounts receivable financing facilities		550
Utilized		(2,244	)
LOCs		(473	)
Net	$	1,203

⁽¹⁾ Includes the $2.75 billion revolving credit facility described below, a $100 million revolving credit facility that expires in December 2009, a $20 million uncommitted line of credit and two $250 million bridge loan facilities.

As of March 31, 2007, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.8 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE, CEI and TE is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE, CEI and TE to incur additional secured debt not otherwise permitted by a specified exception of up to $600 million, $517 million and $130 million, respectively, as of March 31, 2007. Under the provisions of its senior note indenture, JCP&L may issue additional FMB only as collateral for senior notes. As of March 31, 2007, JCP&L had the capability to issue $937 million of additional senior notes upon the basis of FMB collateral.

The applicable earnings coverage tests in the respective charters of OE, TE, Penn and JCP&L are currently inoperative. In the event that any of them issues preferred stock in the future, the applicable earnings coverage test will govern the amount of preferred stock that may be issued. CEI, Met-Ed and Penelec do not have similar restrictions and could issue up to the number of preferred shares authorized under their respective charters.

As of March 31, 2007, approximately $1.0 billion of capacity remained unused under an existing FirstEnergy shelf registration statement filed with the SEC in 2003 to support future securities issuances. The shelf registration provides the flexibility to issue and sell various types of securities, including common stock, debt securities, and share purchase contracts and related share purchase units. As of March 31, 2007, OE had approximately $400 million of capacity remaining unused under its existing shelf registration for unsecured debt securities filed with the SEC in 2006.

On August 24, 2006, FirstEnergy and certain of its subsidiaries entered into a $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 this facility up to a maximum of $3.25 billion. Commitments under the 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 following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations:

	Revolving				Regulatory and
	Credit Facility				Other Short-Term
Borrower	Sub-Limit				Debt Limitations⁽¹⁾
	*(In millions)*
FirstEnergy		$	2,750			$	1,500
OE		500				500
Penn		50				39
CEI		250		⁽²⁾		500
TE		250		⁽²⁾		500
JCP&L		425				412
Met-Ed		250				250		⁽³⁾
Penelec		250				250		⁽³⁾
FES		250				n/a
ATSI		-		⁽⁴⁾		50

⁽¹⁾

As of March 31, 2007.

⁽²⁾

Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice to

the administrative agent that such borrower has senior unsecured debt ratings of at least BBB by

S&P and Baa2 by Moody’s.

⁽³⁾

Excluding amounts which may be borrowed under the regulated money pool.

⁽⁴⁾

The borrowing sub-limit for ATSI may be increased up to $100 million by delivering notice to the

administrative agent that either (i) such borrower has senior unsecured debt ratings of at least BBB-

by S&P and Baa3 by Moody’s or (ii) FirstEnergy has guaranteed the obligations of such borrower

under the facility.

The revolving credit facility, combined with an aggregate $550 million ($229 million unused as of March 31, 2007) of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet working capital requirements and for other general corporate purposes for FirstEnergy and its subsidiaries.

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

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 March 31, 2007, FirstEnergy and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:

Borrower
FirstEnergy	61	%
OE	49	%
Penn	28	%
CEI	57	%
TE	49	%
JCP&L	25	%
Met-Ed	46	%
Penelec	36	%
FES	57	%

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

FirstEnergy's regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy's unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and 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 their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first quarter of 2007 was approximately 5.61% for both the regulated and the unregulated companies' money pools.

FirstEnergy’s access to debt capital markets and costs of financing are impacted by its credit ratings. The following table displays FirstEnergy’s and the Companies’ securities ratings as of March 31, 2007. The ratings outlook from S&P on all securities is Stable. The ratings outlook from Moody’s on all securities is Positive. The ratings outlook from Fitch is Positive for CEI and TE and Stable for all other companies.

Issuer	Securities	S&P	Moody’s	Fitch

FirstEnergy	Senior unsecured	BBB-	Baa3	BBB

OE	Senior unsecured	BBB-	Baa2	BBB

CEI	Senior secured	BBB	Baa2	BBB
	Senior unsecured	BBB-	Baa3	BBB-

TE	Senior secured	BBB	Baa2	BBB
	Senior unsecured	BBB-	Baa3	BBB-

Penn	Senior secured	BBB+	Baa1	BBB+

JCP&L	Senior secured	BBB+	Baa1	A-

Met-Ed	Senior unsecured	BBB	Baa2	BBB

Penelec	Senior unsecured	BBB	Baa2	BBB

On February 21, 2007, FirstEnergy made a $700 million equity investment in FES, all of which was subsequently contributed to FGCO and used to pay-down generation asset transfer-related promissory notes owed to the Ohio Companies and Penn. OE used its $500 million in proceeds to repurchase shares of its common stock from FirstEnergy.

On March 2, 2007, FirstEnergy and FES entered into substantially similar $250 million bridge loan facilities with Morgan Stanley Senior Funding, Inc., proceeds of which were used to fund the March 2, 2007 accelerated share repurchase. FirstEnergy provided a guaranty of FES' loan obligations until such time that FES’ senior unsecured debt was 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. Accordingly, FirstEnergy currently has no liability under the guaranty.

On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or approximately 4.5% of its outstanding common stock at an initial price of $62.63 per share, or a total price of approximately $900 million. This new program supplements the prior repurchase program dated August 10, 2006. Under the prior program, approximately 10.6 million shares were repurchased at an initial purchase price of $600 million, or $56.44 per share. A final purchase price adjustment of $27 million related to the August 2006 agreement was paid in cash by FirstEnergy on April 2, 2007.

On March 27, 2007, CEI issued $250 million of 5.70% unsecured senior notes due 2017. The proceeds of the offering were used to reduce short-term borrowings and for general corporate purposes.

Cash Flows From Investing Activities

Net cash flows used in investing activities resulted principally from property additions. Energy delivery services expenditures for property additions primarily include expenditures related to transmission and distribution facilities. Capital expenditures by the competitive energy services segment are principally generation-related. The following table summarizes investing activities for the first quarter of 2007 and 2006 by segment:

Summary of Cash Flows	Property
Used for Investing Activities	Additions			Investments			Other			Total
Sources (Uses)	*(In millions)*
Three Months Ended March 31, 2007
Energy delivery services	$	(155	)	$	53		$	9		$	(93	)
Competitive energy services		(124	)		(4	)		1			(127	)
Other		(17	)		(16	)		(4	)		(37	)
Inter-Segment reconciling items		-			(15	)		-			(15	)
Total	$	(296	)	$	18		$	6		$	(272	)

Three Months Ended March 31, 2006
Energy delivery services	$	(193	)	$	136		$	(7	)	$	(64	)
Competitive energy services		(244	)		(20	)		(1	)		(265	)
Other		(10	)		41			(3	)		28
Inter-Segment reconciling items		-			(9	)		-			(9	)
Total	$	(447	)	$	148		$	(11	)	$	(310	)

Net cash used for investing activities in the first quarter of 2007 decreased by $38 million compared to the first quarter of 2006. The decrease was principally due to a $151 million decrease in property additions which reflects the replacement of the steam generators and reactor head at Beaver Valley Unit 1 in 2006. Partially offsetting the decrease in property additions was a $78 million decrease in cash investments, primarily from the use of restricted cash investments to repay debt.

During the remaining three quarters of 2007, capital requirements for property additions and capital leases are expected to be $1.2 billion. FirstEnergy and the Companies have additional requirements of approximately $231 million for maturing long-term debt during the remainder of 2007. These cash requirements are expected to be satisfied from a combination of internal cash, short-term credit arrangements, and funds raised in the capital markets.

FirstEnergy's capital spending for the period 2007-2011 is expected to be nearly $8 billion (excluding nuclear fuel), of which approximately $1.4 billion applies to 2007. Investments for additional nuclear fuel during the 2007-2011 period are estimated to be approximately $1.2 billion, of which about $99 million applies to 2007. During the same period, FirstEnergy's nuclear fuel investments are expected to be reduced by approximately $810 million and $104 million, respectively, as the nuclear fuel is consumed.

GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds, and LOCs. Some of the guaranteed contracts contain collateral provisions that are contingent upon FirstEnergy’s credit ratings.

As of March 31, 2007, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances totaled approximately $4.3 billion, as summarized below:

	Maximum
Guarantees and Other Assurances	Exposure
	*(In millions)*
FirstEnergy Guarantees of Subsidiaries
Energy and Energy-Related Contracts ⁽¹⁾	$	910
LOC ⁽²⁾		994
Other ⁽³⁾		592
		2,496
Surety Bonds		106
LOC ⁽⁴⁾⁽⁵⁾		1,737

Total Guarantees and Other Assurances	$	4,339

⁽¹⁾

Issued for open-ended terms, with a 10-day termination right by

FirstEnergy.

⁽²⁾

LOC’s issued by FGCO and NGC in support of pollution control

revenue bonds with various maturities.

⁽³⁾

Includes guarantees of $300 million for OVEC obligations and

$80 million for nuclear decommissioning funding assurances.

⁽⁴⁾

Includes $470 million issued for various terms under LOC capacity

available in FirstEnergy’s revolving credit agreement and an additional

$648 million outstanding in support of pollution control revenue bonds

issued with various maturities.

⁽⁵⁾

Includes approximately $194 million pledged in connection with the

sale and leaseback of Beaver Valley Unit 2 by CEI and TE,

$291 million pledged in connection with the sale and leaseback of

Beaver Valley Unit 2 by OE and $134 million pledged in connection

with the sale and leaseback of Perry Unit 1 by OE.

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of its subsidiaries directly involved in these energy and energy-related transactions or financings where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty's legal claim to be satisfied by FirstEnergy’s other assets. The likelihood that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with ongoing energy and energy-related contracts is remote.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. As of March 31, 2007, FirstEnergy’s maximum exposure under these collateral provisions was $392 million.

Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

FirstEnergy has guaranteed the obligations of the operators of the TEBSA project up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has also provided an LOC ($27 million as of March 31, 2007), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.

OFF-BALANCE SHEET ARRANGEMENTS

FirstEnergy has obligations that are not included on its Consolidated Balance Sheets related to the sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are satisfied through operating lease payments. As of March 31, 2007, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.2 billion.

FirstEnergy has equity ownership interests in certain businesses that are accounted for using the equity method. There are no undisclosed material contingencies related to these investments. Certain guarantees that FirstEnergy does not expect to have a material current or future effect on its financial condition, liquidity or results of operations are disclosed under Guarantees and Other Assurances above.

MARKET RISK INFORMATION

FirstEnergy uses 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 for risk management activities throughout the Company.

Commodity Price Risk

FirstEnergy is exposed to financial and market risks resulting from the fluctuation of interest rates and commodity prices -- electricity, energy transmission, natural gas, coal, nuclear fuel and emission allowances. 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. Derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of FirstEnergy’s derivative hedging contracts qualify for the normal purchase and normal sale exception under SFAS 133 and are therefore excluded from the tables below. Contracts that are not exempt from such treatment include certain power purchase agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policies Act of 1978. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs. The change in the fair value of commodity derivative contracts related to energy production during the first quarter of 2007 is summarized in the following table:

Increase (Decrease) in the Fair Value of Commodity Derivative Contracts	Non-Hedge			Hedge			Total
	*(In millions)*
Change in the Fair Value of Commodity Derivative Contracts:
Outstanding net liability as of January 1, 2007	$	(1,140	)	$	(17	)	$	(1,157	)
Additions/change in value of existing contracts		16			6			22
Settled contracts		96			12			108

Outstanding net liability as of March 31, 2007⁽¹⁾	$	(1,028	)	$	1		$	(1,027	)

Non-commodity Net Assets as of March 31, 2007:
Interest Rate Swaps⁽²⁾		-			(26	)		(26	)
Net Liabilities - Derivatives Contracts as of March 31, 2007	$	(1,028	)	$	(25	)	$	(1,053	)

Impact of First Quarter Changes in Commodity Derivative Contracts:⁽³⁾
Income Statement Effects (Pre-Tax)	$	2		$	-		$	2
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax)	$	-		$	18		$	18
Regulatory Asset (net)	$	(110	)	$	-		$	(110	)

⁽¹⁾ Includes $1.026 billion in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset.

⁽²⁾ Interest rate swaps are treated as cash flow or fair value hedges (see Interest Rate Swap Agreements below).

⁽³⁾ 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 March 31, 2007 as follows:

Balance Sheet Classification	Non-Hedge			Hedge			Total
	*(In millions)*
Current-
Other assets	$	-		$	35		$	35
Other liabilities		(2	)		(34	)		(36	)

Non-Current-
Other deferred charges		37			20			57
Other non-current liabilities		(1,063	)		(46	)		(1,109	)

Net liabilities	$	(1,028	)	$	(25	)	$	(1,053	)

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, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses 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 as of March 31, 2007 are summarized by year in the following table:

Source of Information
- Fair Value by Contract Year	2007⁽¹⁾			2008			2009			2010			2011			Thereafter			Total
	*(In millions)*
Prices actively quoted⁽²⁾	$	-		$	-		$	-		$	-		$	-		$	-		$	-
Other external sources⁽³⁾		(198	)		(257	)		(202	)		(168	)		-			-			(825	)
Prices based on models		-			-			-			-			(101	)		(101	)		(202	)
Total⁽⁴⁾	$	(198	)	$	(257	)	$	(202	)	$	(168	)	$	(101	)	$	(101	)	$	(1,027	)

⁽¹⁾ For the last three quarters of 2007.

⁽²⁾ Exchange traded.

⁽³⁾ Broker quote sheets.

⁽⁴⁾

Includes $1.026 billion in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory

asset.

FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its 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 its derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of March 31, 2007. Based on derivative contracts held as of March 31, 2007, an adverse 10% change in commodity prices would decrease net income by approximately $2 million during the next 12 months.

Interest Rate Swap Agreements- Fair Value Hedges

FirstEnergy utilizes fixed-for-floating interest rate swap agreements as part of its ongoing effort to manage the interest rate risk associated with its debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues - protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates and interest payment dates match those of the underlying obligations. As of March 31, 2007, the debt underlying the $750 million outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 5.74%, which the swaps have converted to a current weighted average variable rate of 6.40%.

	March 31, 2007							December 31, 2006
	Notional		Maturity		Fair			Notional		Maturity		Fair
Interest Rate Swaps	Amount		Date		Value			Amount		Date		Value
	*(In millions)*
Fair value hedges	$	100		2008	$	(2	)	$	100		2008	$	(2)
		50		2010		-			50		2010		(1)
		300		2013		(5	)		300		2013		(6)
		150		2015		(10	)		150		2015		(10)
		50		2025		(1	)		50		2025		(2)
		100		2031		(6	)		100		2031		(6)
	$	750			$	(24	)	$	750			$	(27)

Forward Starting Swap Agreements - Cash Flow Hedges

FirstEnergy utilizes forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with the anticipated future issuances of fixed-rate, long-term debt securities for one or more of its consolidated subsidiaries in 2007 and 2008. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. During the first quarter of 2007, FirstEnergy terminated forward swaps with an aggregate notional value of $250 million. FirstEnergy paid $3 million in cash related to the terminations, which will be recognized over the terms of the associated future debt. There was no ineffective portion associated with the loss. As of March 31, 2007, FirstEnergy had outstanding forward swaps with an aggregate notional amount of $475 million and an aggregate fair value of $(2) million.

	March 31, 2007							December 31, 2006
	Notional		Maturity		Fair			Notional		Maturity		Fair
Forward Starting Swaps	Amount		Date		Value			Amount		Date		Value
	*(In millions)*
Cash flow hedges	$	25		2015	$	-		$	25		2015	$	-
		375		2017		(2	)		200		2017		(4	)
		25		2018		(1	)		25		2018		(1	)
		50		2020		1			50		2020		1
	$	475			$	(2	)	$	300			$	(4	)

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $1.3 billion as of March 31, 2007 and December 31, 2006. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $128 million reduction in fair value as of March 31, 2007.

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. FirstEnergy engages 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.

FirstEnergy maintains credit policies with respect to its 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 its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As of March 31, 2007, the largest credit concentration with one party (currently rated investment grade) represented 11.6% of FirstEnergy‘s total credit risk. Within FirstEnergy’s unregulated energy subsidiaries, 99% of credit exposures, net of collateral and reserves, were with investment-grade counterparties as of March 31, 2007.

Outlook

State Regulatory Matters

In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry restructuring contain similar provisions that are reflected in the Companies' respective state regulatory plans. These provisions include:

·	restructuring the electric generation business and allowing the Companies' customers to select a competitive electric generation supplier other than the Companies;

·	establishing or defining the PLR obligations to customers in the Companies' service areas;

·	providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market;

·	itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges;

·	continuing regulation of the Companies' transmission and distribution systems; and

·	requiring corporate separation of regulated and unregulated business activities.

The Companies and ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $213 million as of March 31, 2007. The following table discloses regulatory assets by company:

	March 31,		December 31,		Increase
Regulatory Assets*	2007		2006		(Decrease)
	*(In millions)*
OE	$	729	$	741	$	(12	)
CEI		854		855		(1	)
TE		237		248		(11	)
JCP&L		2,059		2,152		(93	)
Met-Ed		455		409		46
ATSI		37		36		1
Total	$	4,371	$	4,441	$	(70	)

*	Penelec had net regulatory liabilities of approximately $70 million and $96 million as of March 31, 2007 and December 31, 2006, respectively. These net regulatory liabilities are included in Other Non-current Liabilities on the Consolidated Balance Sheets.

Regulatory assets by source are as follows:

	March 31,			December 31,			Increase
Regulatory Assets By Source	2007			2006			(Decrease)
	*(In millions)*
Regulatory transition costs	$	3,040		$	3,266		$	(226	)
Customer shopping incentives		583			603			(20	)
Customer receivables for future income taxes		270			217			53
Societal benefits charge		4			11			(7	)
Loss on reacquired debt		42			43			(1	)
Employee postretirement benefits		45			47			(2	)
Nuclear decommissioning, decontamination
and spent fuel disposal costs		(108	)		(145	)		37
Asset removal costs		(169	)		(168	)		(1	)
Property losses and unrecovered plant costs		16			19			(3	)
MISO/PJM transmission costs		238			213			25
Fuel costs - RCP		127			113			14
Distribution costs - RCP		202			155			47
Other		81			67			14
Total	$	4,371		$	4,441		$	(70	)

Reliability Initiatives

FirstEnergy is proceeding with the implementation of the recommendations that were issued from various entities, including governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task Force) in late 2003 and early 2004, regarding enhancements to regional reliability that were to be completed subsequent to 2004. FirstEnergy will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades to existing, equipment. The FERC or other applicable government agencies and reliability entities, however, may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures.

As a result of outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L’s service reliability. In 2004, the NJBPU adopted an MOU that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L’s ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a Stipulation that incorporates the final report of an SRM who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The Stipulation also incorporates the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L’s Planning and Operations and Maintenance programs and practices (Focused Audit). On February 11, 2005, JCP&L met with the DRA to discuss reliability improvements. The SRM completed his work and issued his final report to the NJBPU on June 1, 2006. JCP&L filed a comprehensive response to the NJBPU on July 14, 2006. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.

On April 4, 2006, NERC submitted a filing with the FERC seeking approval of mandatory reliability standards. On October 20, 2006, the FERC in turn issued a Proposed Rule on the reliability standards. After a period of public review of the proposal, the FERC issued on March 16, 2007 its Final Rule on Mandatory Reliability Standards for the Bulk-Power System. In this ruling, the FERC approved 83 of the 107 mandatory electric reliability standards proposed by NERC, making them enforceable with penalties and sanctions for noncompliance when the rule becomes effective, which is expected by the summer of 2007. The final rule becomes effective on June 4, 2007. The FERC also directed NERC to submit improvements to 56 standards, endorsing NERC's process for developing reliability standards and its associated work plan. The 24 standards that were not approved remain pending at the FERC awaiting further information from NERC and its regional entities.

Ohio

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

The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP filed on September 9, 2005. On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies’ RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. The following table provides the estimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2007 through 2010:

Amortization							Total
Period	OE		CEI		TE		Ohio

2007	$	179	$	108	$	93	$	380
2008		208		124		119		451
2009		-		216		-		216
2010		-		273		-		273
Total Amortization	$	387	$	721	$	212	$	1,320

Pennsylvania

Met-Ed and Penelec made a comprehensive rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out in accordance with the April 7, 2006 tolling agreement described above. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs, but only for those costs incurred during 2006. In this rate filing, Met-Ed and Penelec also requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of the merger savings, with the comprehensive transmission rate filing case.

The PPUC entered its Opinion and Order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, when new transmission rates were effective, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes in NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission expenses and the transmission deferral. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million). Met-Ed and Penelec filed a Petition for Reconsideration on January 26, 2007 on the issues of consolidated tax savings and rate of return on equity. Other parties filed Petitions for Reconsideration on transmission (including congestion), transmission deferrals and rate design issues. On February 8, 2007, the PPUC entered an order granting Met-Ed’s, Penelec’s and the other parties’ petitions for procedural purposes. Due to that ruling, the period for appeals to the Commonwealth Court was tolled until 30 days after the PPUC entered a subsequent order ruling on the substantive issues raised in the petitions. On March 1, 2007, the PPUC issued three orders: 1) a tentative order regarding the reconsideration by the PPUC of its own order; 2) an order denying the Petitions for Reconsideration of Met-Ed, Penelec and the OCA and denying in part and accepting in part MEIUG’s and PICA’s Petition for Reconsideration; and 3) an order approving the Compliance filing. Comments to the PPUC for reconsideration of its order were filed on March 8, 2007, and the PPUC ruled on the reconsideration on April 13, 2007, making minor changes to rate design as agreed upon by Met-Ed, Penelec and certain other parties.

On May 2, 2007, Penn filed a plan with the PPUC for the procurement of PLR supply from June 2008 through May 2011. The filing proposes multiple, competitive RFPs with staggered delivery periods for fixed-price, tranche-based, pay as bid PLR supply to the residential and commercial classes. The proposal phases out existing promotional rates and eliminates the declining block and the demand components on generation rates for residential and commercial customers. The industrial class PLR service would be provided through an hourly-priced service provided by Penn. Quarterly reconciliation of the differences between the costs of supply and revenues from customers is also proposed. The PPUC is requested to act on the proposal no later than November 2007 for the initial RFP to take place in January 2008.

New Jersey

·	Reduce the total projected electricity demand by 20% by 2020;

·	Meet 22.5% of New Jersey’s electricity needs with renewable energy resources by that date;

·	Reduce air pollution related to energy use;

·	Encourage and maintain economic growth and development;

·	Achieve a 20% reduction in both Customer Average Interruption Duration Index and System Average Interruption Frequency Index by 2020;

·	Unit prices for electricity should remain no more than +5% of the regional average price (region includes New York, New Jersey, Pennsylvania, Delaware, Maryland and the District of Columbia); and

·	Eliminate transmission congestion by 2020.

FERC Matters

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. FirstEnergy filed comments on March 23, 2007, supporting the ancillary service market in concept, but proposing certain changes in MISO’s proposal. MISO has requested FERC action on its filing by June, 2007.

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 First Energy’s operations. MISO, PJM and ATSI will all have to file revised tariffs to comply with FERC’s order.

Environmental Matters

Clean Air Act Compliance

National Ambient Air Quality Standards

Mercury Emissions

W. H. Sammis Plant

Climate Change

Clean Water Act

Regulation of Hazardous Waste

Other Legal Proceedings

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

Power Outages and Related Litigation

Nuclear Plant Matters

Other Legal Matters

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. JCP&L intends to re-file an appeal in federal district court once the damages associated with this case are identified at an individual employee level. JCP&L recognized a liability for the potential $16 million award in 2005.

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”

SFAS 157 - “Fair Value Measurements”

EITF 06-10 - “Accounting for Deferred Compensation and Postretirement Benefit Aspects of Collateral

Split-Dollar Life Insurance Arrangements”

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,
	2007				2006
STATEMENTS OF INCOME	*(In thousands)*

REVENUES:
Electric sales	$	594,344		$	557,229
Excise tax collections		31,254			28,974
Total revenues		625,598			586,203

EXPENSES:
Fuel		3,015			2,951
Purchased power		349,852			283,020
Nuclear operating costs		41,514			41,084
Other operating costs		88,486			90,810
Provision for depreciation		18,848			18,016
Amortization of regulatory assets		45,417			53,861
Deferral of new regulatory assets		(36,649	)		(36,240	)
General taxes		49,745			45,895
Total expenses		560,228			499,397

OPERATING INCOME		65,370			86,806

OTHER INCOME (EXPENSE):
Investment income		26,630			33,042
Miscellaneous income		373			197
Interest expense		(21,022	)		(18,232	)
Capitalized interest		110			491
Subsidiary's preferred stock dividend requirements		-			(156	)
Total other income		6,091			15,342

INCOME BEFORE INCOME TAXES		71,461			102,148

INCOME TAXES		17,426			38,318

NET INCOME		54,035			63,830

PREFERRED STOCK DIVIDEND REQUIREMENTS		-			659

EARNINGS ON COMMON STOCK	$	54,035		$	63,171

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	54,035		$	63,830

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(3,423	)		-
Unrealized gain (loss) on available for sale securities		(126	)		5,735
Other comprehensive income (loss)		(3,549	)		5,735
Income tax expense (benefit) related to other comprehensive income		(1,503	)		2,069
Other comprehensive income (loss), net of tax		(2,046	)		3,666

TOTAL COMPREHENSIVE INCOME	$	51,989		$	67,496

The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these statements.

OHIO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,		December 31,
	2007		2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	694	$	712
Receivables-
Customers (less accumulated provisions of $15,242,000 and $15,033,000,
respectively, for uncollectible accounts)		266,347		234,781
Associated companies		207,377		141,084
Other (less accumulated provisions of $5,409,000 and $1,985,000,
respectively, for uncollectible accounts)		18,106		13,496
Notes receivable from associated companies		527,232		458,647
Prepayments and other		23,657		13,606
		1,043,413		862,326
UTILITY PLANT:
In service		2,649,190		2,632,207
Less - Accumulated provision for depreciation		1,029,438		1,021,918
		1,619,752		1,610,289
Construction work in progress		44,405		42,016
		1,664,157		1,652,305
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies		639,658		1,219,325
Investment in lease obligation bonds		291,225		291,393
Nuclear plant decommissioning trusts		118,636		118,209
Other		37,418		38,160
		1,086,937		1,667,087
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		729,500		741,564
Pension assets		94,682		68,420
Property taxes		60,080		60,080
Unamortized sale and leaseback costs		48,885		50,136
Other		55,011		18,696
		988,158		938,896
	$	4,782,665	$	5,120,614
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	161,424	$	159,852
Short-term borrowings-
Associated companies		16,460		113,987
Other		178,097		3,097
Accounts payable-
Associated companies		150,368		115,252
Other		20,047		13,068
Accrued taxes		135,793		187,306
Accrued interest		17,900		24,712
Other		93,484		64,519
		773,573		681,793
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 175,000,000 shares -
60 and 80 shares outstanding, respectively		1,208,467		1,708,441
Accumulated other comprehensive income		1,162		3,208
Retained earnings		314,043		260,736
Total common stockholder's equity		1,523,672		1,972,385
Long-term debt and other long-term obligations		1,117,635		1,118,576
		2,641,307		3,090,961
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		712,023		674,288
Accumulated deferred investment tax credits		19,640		20,532
Asset retirement obligations		89,428		88,223
Retirement benefits		165,031		167,379
Deferred revenues - electric service programs		77,657		86,710
Other		304,006		310,728
		1,367,785		1,347,860
COMMITMENTS AND CONTINGENCIES (Note 9)
	$	4,782,665	$	5,120,614

The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these balance sheets.

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31,
	2007			2006
	*(In thousands)*
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	54,035		$	63,830
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		18,848			18,016
Amortization of regulatory assets		45,417			53,861
Deferral of new regulatory assets		(36,649	)		(36,240	)
Amortization of lease costs		32,934			32,934
Deferred income taxes and investment tax credits, net		(3,992	)		(3,945	)
Accrued compensation and retirement benefits		(16,794	)		(1,494	)
Pension trust contribution		(20,261	)		-
Decrease (increase) in operating assets-
Receivables		(102,469	)		116,271
Prepayments and other current assets		(6,339	)		(12,136	)
Increase (decrease) in operating liabilities-
Accounts payable		42,095			9,668
Accrued taxes		(46,791	)		27,505
Accrued interest		(6,812	)		3,721
Electric service prepayment programs		(9,053	)		(7,763	)
Other		(4,137	)		4,454
Net cash provided from (used for) operating activities		(59,968	)		268,682

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		77,473			-
Redemptions and Repayments-
Common stock		(500,000	)		-
Long-term debt		(72	)		(59,506	)
Short-term borrowings, net		-			(178,716	)
Dividend Payments-
Common stock		-			(35,000	)
Preferred stock		-			(659	)
Net cash used for financing activities		(422,599	)		(273,881	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(29,888	)		(28,793	)
Proceeds from nuclear decommissioning trust fund sales		12,951			19,054
Investments in nuclear decommissioning trust funds		(12,951	)		(19,054	)
Loan repayments from (loans to) associated companies, net		511,082			(45,224	)
Cash investments		168			78,458
Other		1,187			877
Net cash provided from investing activities		482,549			5,318

Net increase (decrease) in cash and cash equivalents		(18	)		119
Cash and cash equivalents at beginning of period		712			929
Cash and cash equivalents at end of period	$	694		$	1,048

The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these statements.

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Ohio Edison Company:

We have reviewed the accompanying consolidated balance sheets of Ohio Edison Company and its subsidiaries as of March 31, 2007 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005 as discussed in Note 3, Note 2(G) and Note 11 to the consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 8, 2007

OHIO EDISON COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. OE also provides generation services to those customers electing to retain OE as their power supplier. OE’s power supply requirements are provided by FES - an affiliated company.

Results of Operations

Earnings on common stock in the first quarter of 2007 decreased to $54 million from $63 million in the first quarter of 2006. This decrease primarily resulted from higher purchased power costs and reduced other income, partially offset by higher revenues.

Revenues

Revenues increased by $39 million or 6.7% in the first quarter of 2007 compared with the same period in 2006, primarily due to higher retail generation revenues of $48 million, partially offset by decreases in revenues from distribution throughput and wholesale generation sales of $13 million and $3 million, respectively.

Higher retail generation revenues from residential and commercial customers reflected increased sales volume and the impact of higher average unit prices. Average prices increased in part due to the higher composite unit prices that were effective in January 2007 under Penn’s competitive RFP process. Colder weather in the first quarter of 2007 compared to the same period in 2006 contributed to the higher KWH sales to residential and commercial customers (heating degree days increased 15.6% and 11.2% in OE’s and Penn’s service territories, respectively). Retail generation revenues from the industrial sector decreased primarily due to a 9.7 percentage point increase in customer shopping in the first quarter of 2007 as compared to the same period in 2006.

Changes in retail electric generation KWH sales and revenues in the first quarter of 2007 from the same quarter of 2006 are summarized in the following tables:

Retail Generation KWH Sales	Increase (Decrease)

Residential		12.1	%
Commercial		2.7	%
Industrial		(12.9	)%
Net Increase in Generation Sales		0.8	%

Retail Generation Revenues	Increase (Decrease)
	*(In millions)*
Residential	$	37
Commercial		16
Industrial		(5	)
Net Increase in Generation Revenues	$	48

Decreased revenues from distribution throughput to residential and commercial customers reflected the impact of lower composite unit prices, partially offset by higher KWH deliveries due to colder weather in the first quarter of 2007 as compared to the same period in 2006. Decreased revenues from distribution throughput to industrial customers resulted from lower unit prices and reduced KWH deliveries.

Changes in distribution KWH deliveries and revenues in the first quarter 2007 from the same quarter of 2006 are summarized in the following tables.

Changes in Distribution KWH Deliveries	Increase (Decrease)

Residential		9.7	%
Commercial		4.5	%
Industrial		(1.5	)%
Net Increase in Distribution Deliveries		4.3	%

Decreases in Distribution Revenues	*(In millions)*

Residential	$	(1	)
Commercial		(4	)
Industrial		(8	)
Decrease in Distribution Revenues	$	(13	)

Expenses

Total expenses increased by $61 million in the first quarter of 2007 from the same period of 2006. The following table presents changes from the prior year by expense category.

Expenses - Changes	Increase (Decrease)
		*(In millions)*
Purchased power costs	$	67
Other operating costs		(2	)
Provision for depreciation		1
Amortization of regulatory assets		(8	)
Deferral of new regulatory assets		(1	)
General taxes		4
Net Increase in Expenses	$	61

Increased purchased power costs in the first quarter of 2007 primarily reflected higher unit prices associated with Penn’s competitive RFP process and OE’s power supply agreement with FES. The decrease in other operating costs during the first quarter of 2007 was primarily due to lower employee benefit expenses. Lower amortization of regulatory assets was due to the completion of the generation-related transition cost amortization under the OE Companies' respective transition plans by the end of January 2006. General taxes were higher in the first quarter of 2007 as compared to the same period last year as a result of higher real and personal property taxes and KWH excise taxes.

Other Income

Other income decreased $9 million in the first quarter of 2007 compared with the same period of 2006 primarily due to reductions in interest income on notes receivable resulting from principal payments received from associated companies. Higher interest expense in the first quarter of 2007 also contributed to the decrease in other income largely due to OE’s issuance of $600 million of long-term debt in June 2006, partially offset by debt redemptions that have occurred since the first quarter of 2006.

Income Taxes

Capital Resources and Liquidity

During 2007, OE expects to meet its contractual obligations primarily with cash from operations. Borrowing capacity under OE’s credit facilities is available to manage its working capital requirements.

Changes in Cash Position

OE had $694,000 of cash and cash equivalents as of March 31, 2007 compared with $712,000 as of December 31, 2006. The major sources for changes in these balances are summarized below.

Cash Flows From Operating Activities

Net cash provided from operating activities in the first quarter of 2007 and 2006 were as follows:

	Three Months Ended March 31,
Operating Cash Flows	2007			2006
	*(In millions)*
Net income	$	54		$	64
Non-cash charges		31			56
Pension trust contribution		(20	)		-
Working capital and other		(125	)		149
Net cash provided from (used for) operating activities	$	(60	)	$	269

Net cash used for operating activities was $60 million for the first quarter of 2007 compared to $269 million provided from operating activities for the same period of 2006. The $329 million change was due to a $10 million decrease in net income, a $25 million decrease in non-cash charges, a $274 million decrease from changes in working capital and other, and a $20 million pension trust contribution in the first quarter of 2007. The changes in net income and non-cash charges are described above under “Results of Operations.” The decrease from working capital changes primarily reflects changes in accounts receivable of $219 million and accrued taxes of $74 million, partially offset by changes in accounts payable of $32 million.

Cash Flows From Financing Activities

Net cash used for financing activities increased by $149 million in the first quarter of 2007 from the same period last year. This increase primarily resulted from a $500 million repurchase of common stock from FirstEnergy, partially offset by a $316 million decrease in net debt redemptions and the absence in 2007 of a $35 million common stock dividend to FirstEnergy in the first quarter of 2006.

OE had approximately $528 million of cash and temporary cash investments (which include short-term notes receivable from associated companies) and $195 million of short-term indebtedness as of March 31, 2007. OE has authorization from the PUCO to incur short-term debt of up to $500 million through bank facilities and the utility money pool. Penn has authorization from the FERC to incur short-term debt up to its charter limit of $39 million as of March 31, 2007, and also has access to bank facilities and the utility money pool.

On February 21, 2007, FES made a $562 million payment on its fossil generation asset transfer notes owed to OE and Penn. OE used $500 million of the proceeds to repurchase shares of its common stock from FirstEnergy.

See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of OE’s financing capabilities.

Cash Flows From Investing Activities

Net cash provided from investing activities increased $477 million in the first quarter of 2007 from the same period in 2006. The change resulted primarily from a $556 million increase in loan repayments from associated companies (including the $562 million payment from FES described above), partially offset by a $78 million change in cash investments.

During the remaining three quarters of 2007, OE’s capital spending is expected to be approximately $114 million. OE has additional requirements of approximately $4 million for maturing long-term debt during that period. These cash requirements are expected to be satisfied from a combination of cash from operations and short-term credit arrangements. OE’s capital spending for the period 2007-2011 is expected to be about $776 million, of which approximately $146 million applies to 2007.

Off-Balance Sheet Arrangements

Obligations not included on OE’s Consolidated Balance Sheets primarily consist of sale and leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2. As of March 31, 2007, the present value of these operating lease commitments, net of trust investments, was $646 million.

Equity Price Risk

Included in OE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $78 million and $80 million as of March 31, 2007 and December 31, 2006, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $8 million reduction in fair value as of March 31, 2007.

Regulatory Matters

See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to OE.

Environmental Matters

See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to OE.

Other Legal Proceedings

See the “Other Legal Proceedings” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to OE.

New Accounting Standards and Interpretations

See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to OE.

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,
	2007			2006
	*(In thousands)*

REVENUES:
Electric sales	$	422,805		$	390,499
Excise tax collections		18,027			17,311
Total revenues		440,832			407,810

EXPENSES:
Fuel		13,191			13,563
Purchased power		180,657			143,770
Other operating costs		74,951			72,895
Provision for depreciation		18,468			17,201
Amortization of regulatory assets		33,129			31,530
Deferral of new regulatory assets		(33,957	)		(30,526	)
General taxes		38,894			35,070
Total expenses		325,333			283,503

OPERATING INCOME		115,499			124,307

OTHER INCOME (EXPENSE):
Investment income		17,687			26,936
Miscellaneous income (expense)		731			(246	)
Interest expense		(35,740	)		(34,732	)
Capitalized interest		205			673
Total other expense		(17,117	)		(7,369	)

INCOME BEFORE INCOME TAXES		98,382			116,938

INCOME TAXES		34,833			44,525

NET INCOME		63,549			72,413

OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits		1,202			-
Income tax expense related to other comprehensive income		355			-
Other comprehensive income, net of tax		847			-

TOTAL COMPREHENSIVE INCOME	$	64,396		$	72,413

The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these statements.

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2007			2006
	*(In thousands)*
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	775		$	221
Receivables-
Customers (less accumulated provisions of $6,578,000 and $6,783,000,		264,634			245,193
respectively, for uncollectible accounts)
Associated companies		16,705			249,735
Other		3,818			14,240
Notes receivable from associated companies		259,098			27,191
Prepayments and other		1,675			2,314
		546,705			538,894
UTILITY PLANT:
In service		2,140,603			2,136,766
Less - Accumulated provision for depreciation		830,385			819,633
		1,310,218			1,317,133
Construction work in progress		63,588			46,385
		1,373,806			1,363,518
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies		353,293			486,634
Investment in lessor notes		483,996			519,611
Other		13,418			13,426
		850,707			1,019,671
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		1,688,521			1,688,521
Regulatory assets		853,733			854,588
Pension assets		13,456			-
Property taxes		65,000			65,000
Other		65,134			33,306
		2,685,844			2,641,415
	$	5,457,062		$	5,563,498
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	223,676		$	120,569
Short-term borrowings-
Associated companies		102,201			218,134
Accounts payable-
Associated companies		109,744			365,678
Other		6,320			7,194
Accrued taxes		142,355			128,829
Accrued interest		37,155			19,033
Lease market valuation liability		60,200			60,200
Other		29,883			52,101
		711,534			971,738

CAPITALIZATION:
Common stockholder's equity
Common stock, without par value, authorized 105,000,000 shares -		860,165			860,133
67,930,743 shares outstanding
Accumulated other comprehensive loss		(103,584	)		(104,431	)
Retained earnings		752,491			713,201
Total common stockholder's equity		1,509,072			1,468,903
Long-term debt and other long-term obligations		1,937,294			1,805,871
		3,446,366			3,274,774
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		488,325			470,707
Accumulated deferred investment tax credits		19,850			20,277
Lease market valuation liability		532,800			547,800
Retirement benefits		110,039			122,862
Deferred revenues - electric service programs		46,275			51,588
Other		101,873			103,752
		1,299,162			1,316,986
COMMITMENTS AND CONTINGENCIES (Note 9)
	$	5,457,062		$	5,563,498

The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these balance sheets.

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31,
	2007			2006
	*(In thousands)*
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	63,549		$	72,413
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		18,468			17,201
Amortization of regulatory assets		33,129			31,530
Deferral of new regulatory assets		(33,957	)		(30,526	)
Nuclear fuel and capital lease amortization		56			60
Deferred rents and lease market valuation liability		(46,528	)		(54,821	)
Deferred income taxes and investment tax credits, net		(5,453	)		(402	)
Accrued compensation and retirement benefits		(890	)		(172	)
Pension trust contribution		(24,800	)		-
Decrease (increase) in operating assets-
Receivables		224,011			74,518
Prepayments and other current assets		592			515
Increase (decrease) in operating liabilities-
Accounts payable		(256,808	)		(9,424	)
Accrued taxes		13,959			15,691
Accrued interest		18,122			12,802
Electric service prepayment programs		(5,313	)		(4,056	)
Other		(223	)		81
Net cash provided from (used for) operating activities		(2,086	)		125,410

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		247,715			-
Redemptions and Repayments-
Long-term debt		(150	)		(172	)
Short-term borrowings, net		(130,585	)		(57,760	)
Dividend Payments-
Common stock		(24,000	)		(63,000	)
Net cash provided from (used for) financing activities		92,980			(120,932	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(36,682	)		(34,410	)
Loans to associated companies, net		(231,907	)		(9,158	)
Collection of principal on long-term notes receivable		133,341			-
Investments in lessor notes		35,614			44,548
Other		9,294			(5,448	)
Net cash used for investing activities		(90,340	)		(4,468	)

Net increase in cash and cash equivalents		554			10
Cash and cash equivalents at beginning of period		221			207
Cash and cash equivalents at end of period	$	775		$	217


The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral part of these statements.

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of The Cleveland Electric Illuminating Company:

We have reviewed the accompanying consolidated balance sheets of The Cleveland Electric Illuminating Company and its subsidiaries as of March 31, 2007 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(G) and Note 11 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 8, 2007

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in northeastern Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain CEI as their power supplier. CEI’s power supply requirements are primarily provided by FES - an affiliated company.

Results of Operations

Net income in the first quarter of 2007 decreased to $64 million from $72 million in the same period of 2006. This decrease resulted primarily from higher purchased power costs and lower investment income, partially offset by higher revenues.

Revenues

Revenues increased by $33 million or 8% in the first quarter of 2007 from the first quarter of 2006 primarily due to higher retail and wholesale generation revenues. Retail generation revenues increased $22 million due to increased KWH sales and higher composite unit prices. Colder weather in the first quarter of 2007 compared to the same period in 2006 contributed to the higher KWH sales to residential and commercial customers (heating degree days increased 18.1%). KWH sales to industrial customers increased in part due to a reduction in customer shopping during the first quarter of 2007.

Wholesale generation revenues increased by $11 million primarily due to higher unit prices for PSA sales to associated companies, partially offset by a decrease in sales volume due in part to maintenance outages at the Bruce Mansfield Plant in the first quarter of 2007. CEI sells KWH from its leasehold interests in the Bruce Mansfield Plant to FGCO.

Increases in retail electric generation sales and revenues in the first quarter of 2007 from the same period of 2006 are summarized in the following tables:

Retail Generation KWH Sales	Increase
Residential		8.0	%
Commercial		7.1	%
Industrial		3.3	%
Total Retail Electric Generation Sales		5.6	%

Retail Generation Revenues	Increase
	*(In millions*)
Residential	$	7
Commercial		7
Industrial		8
Total Retail Generation Revenues	$	22

Revenues from distribution throughput decreased $2 million in the first quarter of 2007 compared to the same period of 2006. This decrease was primarily a result of lower composite unit prices in all customer classes, partially offset by increased KWH deliveries to residential and commercial customers due to colder weather in the first quarter of 2007 as compared to the same period in 2006. The lower composite unit prices in part reflected the completion of the generation-related transition cost recovery under CEI’s transition plan by the end of January 2006.

Changes in distribution KWH deliveries and revenues in the first quarter of 2007 compared to the same period of 2006 are summarized in the following tables.

Distribution KWH Deliveries	Increase
Residential		8.0	%
Commercial		4.9	%
Industrial		2.1	%
Total Increase in Distribution Deliveries		4.6	%

Distribution Revenues	Increase (Decrease)
	*(In millions)*
Residential	$	2
Commercial		1
Industrial		(5	)
Net Decrease in Distribution Revenues	$	(2	)

Expenses

Total expenses increased by $42 million in the first quarter of 2007 compared to the same period of 2006. The following table presents changes from the prior year by expense category:

Expenses - Changes	Increase (Decrease)
	*(In millions)*
Purchased power costs	$	37
Other operating costs		2
Provision for depreciation		1
Amortization of regulatory assets		2
Deferral of new regulatory assets		(4	)
General taxes		4
Net increase in expenses	$	42

Higher purchased power costs in the first quarter of 2007 compared to the first quarter of 2006 primarily reflected higher unit prices associated with the power supply agreement with FES and an increase in KWH purchases to meet CEI’s higher retail generation sales requirements. The change in the deferral of new regulatory assets in the first quarter of 2007 reflects a higher level of MISO costs that were deferred in excess of transmission revenue and increased distribution cost deferrals under CEI’s RCP. General taxes were higher in the first quarter of 2007 as compared to the same period last year as a result of higher real and personal property taxes and KWH excise taxes.

Other Expense

Other expense increased by $10 million in the first quarter of 2007 compared to the same period of 2006 primarily due to lower investment income on associated company notes receivable. CEI received principal repayments from FGCO and NGC subsequent to the first quarter of 2006 on notes receivable related to the generation asset transfers.

Capital Resources and Liquidity

During 2007, CEI expects to meet its contractual obligations with cash from operations and short-term credit arrangements.

Changes in Cash Position

As of March 31, 2007, CEI had $775,000 of cash and cash equivalents, compared with $221,000 as of December 31, 2006. The major sources of changes in these balances are summarized below.

Cash Flows from Operating Activities

Cash provided from operating activities during the first quarter of 2007, compared with the first quarter of 2006, were as follows:

	Three Months Ended March 31,
Operating Cash Flows	2007			2006
	*(In millions)*
Net Income	$	64		$	72
Non-cash credits		(40	)		(41	)
Pension trust contribution		(25	)		-
Working capital and other		(1	)		94
Net cash provided from (used for) operating activities	$	(2	)	$	125

Net cash provided from operating activities decreased by $127 million in the first quarter of 2007 compared to the same period of 2006 due primarily to a $25 million pension trust contribution in the first quarter of 2007 and a $95 million change in working capital and other. The decrease from working capital changes was due primarily to changes in accounts payable of $247 million, partially offset by changes in accounts receivable of $149 million. The decreases of $8 million from net income and $1 million from non-cash credits are described above under “Results of Operations.”

Cash Flows from Financing Activities

Net cash provided from financing activities was $93 million in the first quarter of 2007 compared to net cash used of $121 million in the first quarter of 2006. The change reflects $248 million of new long-term debt financing and a $39 million decrease in common stock dividend payments to FirstEnergy, partially offset by a $73 million increase in repayments of short-term borrowings.

CEI had $260 million of cash and temporary investments (which included short-term notes receivable from associated companies) and approximately $102 million of short-term indebtedness as of March 31, 2007. CEI has obtained authorization from the PUCO to incur short-term debt of up to $500 million through bank facilities and the utility money pool.

On March 27, 2007, CEI issued $250 million of 5.70% unsecured senior notes due 2017. The proceeds of the offering were used to reduce short-term borrowings and for general corporate purposes.

See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of CEI’s financing capabilities.

Cash Flows from Investing Activities

Net cash used for investing activities increased by $86 million in the first quarter of 2007 compared to the same period of 2006. The change was primarily due to increased loans to associated companies, partially offset by the collection of principal on long-term notes receivable.

CEI’s capital spending for the last three quarters of 2007 is expected to be about $130 million. These cash requirements are expected to be satisfied with cash from operations and short-term credit arrangements. CEI’s capital spending for the period 2007-2011 is expected to be about $841 million, of which approximately $158 million applies to 2007.

Off-Balance Sheet Arrangements

Obligations not included on CEI’s Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant. As of March 31, 2007, the present value of these operating lease commitments, net of trust investments, total $89 million.

Regulatory Matters

See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to CEI.

Environmental Matters

See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to CEI.

Other Legal Proceedings

See the “Other Legal Proceedings” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to CEI.

New Accounting Standards and Interpretations

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,
	2007			2006

STATEMENTS OF INCOME	*(In thousands)*

REVENUES:
Electric sales	$	233,056		$	210,874
Excise tax collections		7,400			7,103
Total revenues		240,456			217,977

EXPENSES:
Fuel		10,147			9,762
Purchased power		96,169			75,420
Nuclear operating costs		17,721			17,332
Other operating costs		42,921			40,425
Provision for depreciation		9,117			8,097
Amortization of regulatory assets		23,876			24,456
Deferral of new regulatory assets		(13,481	)		(13,656	)
General taxes		13,734			12,931
Total expenses		200,204			174,767

OPERATING INCOME		40,252			43,210

OTHER INCOME (EXPENSE):
Investment income		7,225			9,780
Miscellaneous expense		(3,100	)		(2,684	)
Interest expense		(7,503	)		(4,310	)
Capitalized interest		83			214
Total other income (expense)		(3,295	)		3,000

INCOME BEFORE INCOME TAXES		36,957			46,210

INCOME TAXES		11,097			17,204

NET INCOME		25,860			29,006

PREFERRED STOCK DIVIDEND REQUIREMENTS		-			1,275

EARNINGS ON COMMON STOCK	$	25,860		$	27,731

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	25,860		$	29,006

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		573			-
Unrealized gain (loss) on available for sale securities		379			(1,138	)
Other comprehensive income (loss)		952			(1,138	)
Income tax expense (benefit) related to other
comprehensive income		334			(411	)
Other comprehensive income (loss), net of tax		618			(727	)

TOTAL COMPREHENSIVE INCOME	$	26,478		$	28,279

The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements.

THE TOLEDO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2007			2006
	*(In thousands)*
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	201		$	22
Receivables-
Customers		557			772
Associated companies		14,059			13,940
Other (less accumulated provisions of $433,000 and $430,000,
respectively, for uncollectible accounts)		3,769			3,831
Notes receivable from associated companies		109,195			100,545
Prepayments and other		539			851
		128,320			119,961
UTILITY PLANT:
In service		897,270			894,888
Less - Accumulated provision for depreciation		398,461			394,225
		498,809			500,663
Construction work in progress		16,787			16,479
		515,596			517,142
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes		154,689			169,493
Long-term notes receivable from associated companies		96,589			128,858
Nuclear plant decommissioning trusts		62,075			61,094
Other		1,840			1,871
		315,193			361,316
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		500,576			500,576
Regulatory assets		237,220			247,595
Pension assets		4,796			-
Property taxes		22,010			22,010
Other		50,514			30,042
		815,116			800,223
	$	1,774,225		$	1,798,642
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	30,000		$	30,000
Accounts payable-
Associated companies		67,253			84,884
Other		4,119			4,021
Notes payable to associated companies		107,049			153,567
Accrued taxes		54,781			47,318
Lease market valuation liability		24,600			24,600
Other		49,916			37,551
		337,718			381,941
CAPITALIZATION:
Common stockholder's equity-
Common stock, $5 par value, authorized 60,000,000 shares -
29,402,054 shares outstanding		147,010			147,010
Other paid-in capital		166,799			166,786
Accumulated other comprehensive loss		(36,186	)		(36,804	)
Retained earnings		230,200			204,423
Total common stockholder's equity		507,823			481,415
Long-term debt		358,254			358,281
		866,077			839,696
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		165,004			161,024
Accumulated deferred investment tax credits		10,806			11,014
Lease market valuation liability		212,650			218,800
Retirement benefits		75,265			77,843
Asset retirement obligations		26,987			26,543
Deferred revenues - electric service programs		20,930			23,546
Other		58,788			58,235
		570,430			577,005
COMMITMENTS AND CONTINGENCIES (Note 9)
	$	1,774,225		$	1,798,642

The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these balance sheets.

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31,
	2007			2006
	*(In thousands)*
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	25,860		$	29,006
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		9,117			8,097
Amortization of regulatory assets		23,876			24,456
Deferral of new regulatory assets		(13,481	)		(13,656	)
Deferred rents and lease market valuation liability		(10,891	)		(16,084	)
Deferred income taxes and investment tax credits, net		(3,639	)		(8,453	)
Accrued compensation and retirement benefits		(756	)		(293	)
Pension trust contribution		(7,659	)		-
Decrease (increase) in operating assets-
Receivables		158			(8,793	)
Prepayments and other current assets		312			366
Increase (decrease) in operating liabilities-
Accounts payable		(17,533	)		(15,969	)
Accrued taxes		9,379			20,401
Accrued interest		3,951			(668	)
Electric service prepayment programs		(2,616	)		(2,231	)
Other		(1,320	)		1,282
Net cash provided from operating activities		14,758			17,461

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		-			55,539
Redemptions and Repayments-
Preferred stock		-			(30,000	)
Short-term borrowings, net		(46,518	)		-
Dividend Payments-
Common stock		-			(25,000	)
Preferred stock		-			(1,275	)
Net cash used for financing activities		(46,518	)		(736	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(6,064	)		(15,044	)
Loans to associated companies		(8,583	)		(11,270	)
Collection of principal on long-term notes receivable		32,202			-
Investments in lessor notes		14,804			9,335
Proceeds from nuclear decommissioning trust fund sales		16,863			13,793
Investments in nuclear decommissioning trust funds		(16,863	)		(13,793	)
Other		(420	)		254
Net cash provided from (used for) investing activities		31,939			(16,725	)

Net change in cash and cash equivalents		179			-
Cash and cash equivalents at beginning of period		22			15
Cash and cash equivalents at end of period	$	201		$	15

The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements.

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of The Toledo Edison Company:

We have reviewed the accompanying consolidated balance sheets of The Toledo Edison Company and its subsidiary as of March 31, 2007 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 8, 2007

THE TOLEDO EDISON COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain TE as their power supplier. TE’s power supply requirements are provided by FES - an affiliated company.

Results of Operations

Earnings on common stock in the first quarter of 2007 decreased to $26 million from $28 million in the first quarter of 2006. This decrease resulted primarily from higher purchased power and other operating costs, partially offset by higher revenues.

Revenues

Revenues increased $22 million or 10.3% in the first quarter of 2007 compared to the same period of 2006 primarily due to higher retail generation revenues of $12 million and higher wholesale generation revenues of $10 million. Retail generation revenues increased for all customer sectors in the first quarter of 2007 compared to the same period of 2006 due to higher average prices and increased sales volume. Average prices increased primarily due to higher composite unit prices for retail generation shopping customers returning to TE. Generation services provided by alternative suppliers as a percentage of total sales delivered in TE’s franchise area decreased by 4.7 percentage points and 1.5 percentage points for residential and commercial customers, respectively. The increase in sales volume also resulted from colder weather in the first quarter of 2007 compared to the same period in 2006 (heating degree days increased 17.5%).

The increase in wholesale revenues resulted from higher unit prices for PSA sales to associated companies, partially offset by a decrease in generation available for sale due in part to a maintenance outage at Mansfield Unit 2 in the first quarter of 2007. TE sells KWH from its leasehold interests in Beaver Valley Unit 2 and the Bruce Mansfield Plant to CEI and FGCO, respectively.

Increases in retail electric generation KWH sales and revenues in the first quarter of 2007 from the first quarter of 2006 are summarized in the following tables.

Retail Generation KWH Sales	Increase
Residential		13.7	%
Commercial		5.3	%
Industrial		0.8	%
Total Retail Electric Generation Sales		5.0	%

Retail Generation Revenues	Increase
	*(In millions*)
Residential	$	4
Commercial		3
Industrial		5
Total Retail Generation Revenues	$	12

Revenues from distribution throughput decreased by $2 million in the first quarter in 2007 compared to the same period in 2006 primarily due to lower composite unit prices in the industrial customer sector, partially offset by higher KWH deliveries to residential and commercial customers. The higher KWH deliveries to residential and commercial customers in the first quarter of 2007 reflected the impact of colder weather in the first quarter of 2007 compared to the same period in 2006.

Changes in distribution KWH deliveries and revenues in the first quarter of 2007 from the first quarter of 2006 are summarized in the following tables.

Distribution KWH Deliveries	Increase
Residential		8.0	%
Commercial		2.8	%
Industrial		0.4	%
Total Increase in Distribution Deliveries		3.0	%

Distribution Revenues	Increase (Decrease)
	*(In millions)*
Residential	$	2
Commercial		-
Industrial		(4	)
Net Decrease in Distribution Revenues	$	(2	)

Expenses

Total expenses increased $25 million in the first quarter of 2007 from the same quarter of 2006. The following table presents changes from the prior year by expense category:

Expenses	*(In millions)*
Purchased power costs	$	21
Other operating costs		2
Provision for depreciation		1
General taxes		1
Increase in expenses	$	25

Higher purchased power costs in the first quarter of 2007 compared to the first quarter of 2006 reflected higher unit prices associated with the power supply agreement with FES and an increase in KWH purchases to meet the higher retail generation sales requirements. Other operating costs were higher due to a $2 million increase in MISO network transmission expenses in the first quarter of 2007 compared to the same period in 2006.

Other Expense

Other expense increased $6 million in the first quarter of 2007 compared to the same period of 2006 primarily due to lower investment income and higher interest expense. A $3 million decrease in investment income resulted primarily from the principal repayments in 2006 on notes receivable from associated companies. Higher interest expense of $3 million is largely associated with new long-term debt issuances in November 2006.

Capital Resources and Liquidity

During 2007, TE expects to meet its contractual obligations primarily with cash from operations. Borrowing capacity under TE’s credit facilities is available to manage its working capital requirements.

Changes in Cash Position

As of March 31, 2007, TE had $201,000 of cash and cash equivalents, compared with $22,000 as of December 31, 2006. The major changes in these balances are summarized below.

Cash Flows From Operating Activities

Net cash provided from operating activities in the first quarter of 2007 and 2006 were as follows:

	Three Months Ended March 31,
Operating Cash Flows	2007			2006
	*(In millions)*
Net income	$	26		$	29
Non-cash charges (credits)		2			(8	)
Pension trust contribution		(8	)		-
Working capital and other		(5	)		(3	)
Net cash provided from operating activities	$	15		$	18

Net cash provided from operating activities decreased $3 million in the first quarter of 2007 compared to the same period of 2006 as a result of a $3 million decrease in net income, an $8 million pension trust contribution in the first quarter of 2007 and a $2 million decrease from changes in working capital and other, partially offset by a $10 million increase in net non-cash charges. The increase in non-cash charges reflects changes in deferred lease costs and deferred income taxes. The changes in net income are described above under “Results of Operations.”

Cash Flows From Financing Activities

Net cash used for financing activities increased by $46 million in the first quarter of 2007 compared to the same period of 2006. The increase resulted from a $102 million decrease in net short-term borrowings, partially offset by a $30 million decrease in preferred stock redemptions and the absence in 2007 of a $25 million common stock dividend to FirstEnergy in the first quarter of 2006.

TE had $109 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $107 million of short-term indebtedness as of March 31, 2007. TE has authorization from the PUCO to incur short-term debt of up to $500 million through bank facilities and the utility money pool.

See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of TE’s financing capabilities.

Cash Flows From Investing Activities

Net cash provided from investing activities was $32 million in the first quarter of 2007 compared to net cash used for investing activities of $17 million in the first quarter of 2006. The change was primarily due to a net increase of $35 million from loan activity with associated companies, a $9 million decrease in property additions and a $5 million increase from investments in lessor notes.

TE’s capital spending for the last three quarters of 2007 is expected to be about $55 million. TE has additional requirements of $30 million for maturing long-term debt during the remainder of 2007. These cash requirements are expected to be satisfied primarily with cash from operations and short-term credit arrangements. TE’s capital spending for the period 2007-2011 is expected to be nearly $325 million, of which approximately $64 million applies to 2007.

Off-Balance Sheet Arrangements

Obligations not included on TE’s Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley Unit 2. As of March 31, 2007, the present value of these operating lease commitments, net of trust investments, total $500 million.

Regulatory Matters

See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to TE.

Environmental Matters

See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to TE.

Other Legal Proceedings

See the “Other Legal Proceedings” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to TE.

New Accounting Standards and Interpretations

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,
	2007			2006
STATEMENTS OF INCOME	*(In thousands)*

REVENUES:
Electric sales	$	670,907		$	563,550
Excise tax collections		12,836			12,242
Total revenues		683,743			575,792

EXPENSES:
Purchased power		386,497			315,710
Other operating costs		74,651			83,028
Provision for depreciation		20,516			20,628
Amortization of regulatory assets		95,228			66,745
General taxes		16,999			16,232
Total expenses		593,891			502,343

OPERATING INCOME		89,852			73,449

OTHER INCOME (EXPENSE):
Miscellaneous income		3,061			3,543
Interest expense		(22,416	)		(20,616	)
Capitalized interest		513			892
Total other expense		(18,842	)		(16,181	)

INCOME BEFORE INCOME TAXES		71,010			57,268

INCOME TAXES		32,664			23,558

NET INCOME		38,346			33,710

PREFERRED STOCK DIVIDEND REQUIREMENTS		-			125

EARNINGS ON COMMON STOCK	$	38,346		$	33,585

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	38,346		$	33,710

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(2,115	)		-
Unrealized gain on derivative hedges		97			69
Other comprehensive income (loss)		(2,018	)		69
Income tax expense (benefit) related to other
comprehensive income		(984	)		28
Other comprehensive income (loss), net of tax		(1,034	)		41

TOTAL COMPREHENSIVE INCOME	$	37,312		$	33,751

The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these statements.

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2007			2006
	*(In thousands)*
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	46		$	41
Receivables-
Customers (less accumulated provisions of $3,005,000 and $3,524,000,
respectively, for uncollectible accounts)		270,534			254,046
Associated companies		863			11,574
Other (less accumulated provisions of $716,000
in 2007 for uncollectible accounts)		57,628			40,023
Notes receivable - associated companies		23,924			24,456
Materials and supplies, at average cost		2,044			2,043
Prepaid taxes		1,127			13,333
Other		12,834			18,076
		369,000			363,592
UTILITY PLANT:
In service		4,030,132			4,029,070
Less - Accumulated provision for depreciation		1,468,470			1,473,159
		2,561,662			2,555,911
Construction work in progress		92,008			78,728
		2,653,670			2,634,639
OTHER PROPERTY AND INVESTMENTS:
Nuclear fuel disposal trust		171,007			171,045
Nuclear plant decommissioning trusts		166,342			164,108
Other		2,056			2,047
		339,405			337,200
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		2,058,636			2,152,332
Goodwill		1,962,361			1,962,361
Pension assets		36,034			14,660
Other		15,499			17,781
		4,072,530			4,147,134
	$	7,434,605		$	7,482,565
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	153,986		$	32,683
Short-term borrowings-
Associated companies		223,611			186,540
Accounts payable-
Associated companies		26,970			80,426
Other		151,777			160,359
Accrued taxes		23,573			1,451
Accrued interest		24,252			14,458
Cash collateral from suppliers		32,446			32,300
Other		94,036			96,150
		730,651			604,367
CAPITALIZATION:
Common stockholder's equity-
Common stock, $10 par value, authorized 16,000,000 shares-
15,371,270 shares outstanding		150,093			150,093
Other paid-in capital		2,908,315			2,908,279
Accumulated other comprehensive loss		(45,288	)		(44,254	)
Retained earnings		168,732			145,480
Total common stockholder's equity		3,181,852			3,159,598
Long-term debt and other long-term obligations		1,189,664			1,320,341
		4,371,516			4,479,939
NONCURRENT LIABILITIES:
Power purchase contract loss liability		1,062,658			1,182,108
Accumulated deferred income taxes		796,940			803,944
Nuclear fuel disposal costs		185,856			183,533
Asset retirement obligations		85,722			84,446
Other		201,262			144,228
		2,332,438			2,398,259
COMMITMENTS AND CONTINGENCIES (Note 9)
	$	7,434,605		$	7,482,565

The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these balance sheets.

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31,
	2007			2006
	*(In thousands)*
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	38,346		$	33,710
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		20,516			20,628
Amortization of regulatory assets		95,228			66,745
Deferred purchased power and other costs		(78,303	)		(61,868	)
Deferred income taxes and investment tax credits, net		8,076			3,826
Accrued compensation and retirement benefits		(8,374	)		(2,736	)
Cash collateral from (returned to) suppliers		1			(108,657	)
Pension trust contribution		(17,800	)		-
Decrease (increase) in operating assets:
Receivables		(23,381	)		48,005
Materials and supplies		(1	)		255
Prepaid taxes		11,946			8,992
Other current assets		454			(929	)
Increase (decrease) in operating liabilities:
Accounts payable		(62,038	)		(68,993	)
Accrued taxes		31,599			32,106
Accrued interest		9,794			13,769
Other		(3,832	)		(5,773	)
Net cash provided from (used for) operating activities		22,231			(20,920	)

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		37,071			96,812
Redemptions and Repayments-
Long-term debt		(9,569	)		(3,731	)
Dividend Payments-
Common stock		(15,000	)		(25,000	)
Preferred stock		-			(125	)
Net cash provided from financing activities		12,502			67,956

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(40,015	)		(45,361	)
Loan repayments from (loans to) associated companies, net		532			(3,132	)
Proceeds from nuclear decommissioning trust fund sales		22,407			45,865
Investments in nuclear decommissioning trust funds		(23,131	)		(46,588	)
Other		5,479			2,181
Net cash used for investing activities		(34,728	)		(47,035	)

Net increase in cash and cash equivalents		5			1
Cash and cash equivalents at beginning of period		41			102
Cash and cash equivalents at end of period	$	46		$	103

The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these statements.

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Jersey Central Power & Light Company:

We have reviewed the accompanying consolidated balance sheets of Jersey Central Power & Light Company and its subsidiaries as of March 31, 2007 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 8, 2007

JERSEY CENTRAL POWER & LIGHT COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts business in New Jersey, providing regulated electric transmission and distribution services. JCP&L also provides generation services to those customers electing to retain JCP&L as their power supplier.

Results of Operations

Earnings on common stock in the first quarter of 2007 increased to $38 million from $34 million in the same period in 2006 primarily due to higher revenues and lower other operating costs, partially offset by higher purchased power costs and increased amortization of regulatory assets.

Revenues

Revenues increased $108 million or 18.7% in the first quarter of 2007 compared with the same period of 2006 due to higher retail and wholesale generation revenues. Retail generation revenues increased by $62 million in the first quarter of 2007 as compared to the previous year in all customer classes (residential - $36 million, commercial - $24 million and industrial - $2 million). The increases were due to higher unit prices resulting from the BGS auction effective in May 2006 and increased sales volume (residential - 4.4% and commercial - 1.2%) as a result of colder weather in the first quarter of 2007 (heating degree days were 12.9% greater than the first quarter of 2006).

Industrial generation KWH sales declined by 1.4% from the same period of 2006, reflecting a slight increase in the level of customer shopping. Wholesale sales revenues increased $8 million primarily due to higher market prices and a 1.0% increase in sales volume as compared to the first quarter of 2006.

Revenues from distribution throughput increased by $28 million in the first quarter of 2007 compared to the same period of 2006 due to higher composite unit prices and a 3.9% increase in KWH volume, reflecting the colder weather in JCP&L’s service territory. The higher unit prices resulted from a NUGC rate increase effective in December 2006 as approved by the NJBPU.

Increases in KWH sales by customer class in the first quarter of 2007 compared to the same period of 2006 are summarized in the following table:

Increases in KWH Sales

Electric Generation:
Retail	2.8	%
Wholesale	1.0	%
Total Electric Generation Sales	2.4	%

Distribution Deliveries:
Residential	4.4	%
Commercial	4.2	%
Industrial	1.7	%
Total Distribution Deliveries	3.9	%

The higher revenues in the first quarter of 2007 also reflect a $2 million increase in property rents and higher transition funding revenues of $8 million. The increased transition funding revenues resulted from the securitization of deferred costs associated with JCP&L’s supply of BGS in August 2006.

Expenses

Total expenses increased by $92 million in the first quarter of 2007 compared to the first quarter of 2006. The following table presents changes from the prior year by expense category:

Expenses - Changes	Increase (Decrease)
	*(In millions)*

Purchased power costs	$	71
Other operating costs		(8	)
Amortization of regulatory assets		28
General taxes		1
Net increase in expenses	$	92

Purchased power costs increased $71 million in the first quarter of 2007 compared to the same period of 2006, reflecting higher prices from the BGS auction effective in May 2006 and a 8.9% increase in KWH purchases to meet higher customer demand as described above. The decrease of $8 million in other operating costs in the first quarter of 2007 was due in part to lower postretirement benefits costs and a reduction in associated company service billings. Amortization of regulatory assets increased $28 million in the first quarter of 2007 as a result of higher transition cost recovery primarily associated with the December 2006 NUGC rate increase.

Capital Resources and Liquidity

During 2007, JCP&L expects to meet its contractual obligations with a combination of cash from operations and funds from the capital markets. Borrowing capacity under JCP&L’s credit facilities is available to manage its working capital requirements.

Changes in Cash Position

As of March 31, 2007, JCP&L had $46,000 of cash and cash equivalents compared with $41,000 as of December 31, 2006. The major sources for changes in these balances are summarized below.

Cash Flows From Operating Activities

Net cash provided from operating activities was $22 million in the first quarter of 2007 compared to net cash used for operating activities of $21 million in the first quarter of 2006, as summarized in the following table:

	Three Months Ended March 31,
Operating Cash Flows	2007			2006
	*(In millions)*
Net income	$	38		$	34
Net non-cash charges		37			27
Pension trust contribution		(18	)		-
Cash collateral from (returned to) suppliers		1			(109	)
Working capital and other		(36	)		27
Net cash provided from (used for) operating activities	$	22		$	(21	)

Net cash provided from operating activities increased $43 million in the first quarter of 2007 from the same period in 2006. This increase was primarily due to the absence in 2007 of $109 million of cash collateral payments made to suppliers in the first quarter of 2006, partially offset by a $63 million decrease from working capital (primarily due to changes in receivables) and an $18 million pension trust contribution in the first quarter of 2007. The changes in net income and non-cash charges are described above under “Results of Operations.”

Cash Flows From Financing Activities

Net cash provided from financing activities was $13 million in the first quarter of 2007 as compared to $68 million in the same period of 2006. The $55 million decrease resulted from a $59 million reduction in short-term borrowings and a $6 million increase in debt redemptions in the first quarter of 2007, partially offset by a $10 million decrease in common stock dividend payments to FirstEnergy.

JCP&L had approximately $24 million of cash and temporary investments (which includes short-term notes receivable from associated companies) and approximately $224 million of short-term indebtedness as of March 31, 2007. JCP&L has authorization from the FERC to incur short-term debt up to its charter limit of $412 million through bank facilities and the utility money pool.

See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of JCP&L’s financing capabilities.

Cash Flows From Investing Activities

Net cash used in investing activities was $35 million in the first quarter of 2007 compared to $47 million in the same period of 2006. The $12 million change primarily resulted from a $5 million reduction in property additions and an increase in loans from associated companies.

During the last three quarters of 2007, capital requirements for property additions and improvements are expected to be about $152 million. JCP&L has cash requirements of $23 million for maturing long-term debt during the remainder of 2007. These cash requirements are expected to be satisfied from a combination of cash from operations, short-term credit arrangements and funds from the capital markets. JCP&L’s capital spending for the period 2007-2011 is expected to be about $1.3 billion, of which approximately $192 million applies to 2007.

Market Risk Information

During the first quarter of 2007, net liabilities for commodity derivative contracts decreased by $117 million as a result of settled contracts ($104 million) and changes in the value of existing contracts ($13 million). These non-trading contracts (primarily with NUG entities) are adjusted to fair value at the end of each quarter with a corresponding offset to regulatory assets, resulting in no impact to current period earnings. Outstanding net liabilities for commodity derivative contracts were $1.1 billion and $1.2 billion as of March 31, 2007 and December 31, 2006, respectively. See the “Market Risk Information” section of JCP&L’s 2006 Annual Report on Form 10-K for additional discussion of market risk.

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $98 million and $97 million as of March 31, 2007 and December 31, 2006, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $10 million reduction in fair value as of March 31, 2007.

Regulatory Matters

See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to JCP&L.

Environmental Matters

See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to JCP&L.

Other Legal Proceedings

See the “Other Legal Proceedings” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to JCP&L.

New Accounting Standards and Interpretations

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,

	2007			2006
	*(In thousands)*

REVENUES:
Electric sales	$	352,136		$	294,037
Gross receipts tax collections		18,120			17,176
Total revenues		370,256			311,213

EXPENSES:
Purchased power		191,589			159,887
Other operating costs		98,018			61,079
Provision for depreciation		10,284			10,905
Amortization of regulatory assets		34,140			30,048
Deferral of new regulatory assets		(42,726	)		-
General taxes		21,052			20,621
Total expenses		312,357			282,540

OPERATING INCOME		57,899			28,673

OTHER INCOME (EXPENSE):
Interest income		7,726			8,750
Miscellaneous income		1,109			2,612
Interest expense		(11,756	)		(11,184	)
Capitalized interest		260			267
Total other income (expense)		(2,661	)		445

INCOME BEFORE INCOME TAXES		55,238			29,118

INCOME TAXES		23,599			11,204

NET INCOME		31,639			17,914

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(1,452	)		-
Unrealized gain on derivative hedges		84			84
Other comprehensive income (loss)		(1,368	)		84
Income tax expense (benefit) related to other
comprehensive income		(692	)		35
Other comprehensive income (loss), net of tax		(676	)		49

TOTAL COMPREHENSIVE INCOME	$	30,963		$	17,963

The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements.

METROPOLITAN EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2007			2006
	*(In thousands)*
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	129		$	130
Receivables-
Customers (less accumulated provisions of $4,063,000 and $4,153,000,
respectively, for uncollectible accounts)		154,261			127,084
Associated companies		10,909			3,604
Other		27,337			8,107
Notes receivable from associated companies		33,931			31,109
Prepaid gross receipts taxes		41,100			-
Prepayments and other		988			14,957
		268,655			184,991
UTILITY PLANT:
In service		1,927,244			1,920,563
Less - Accumulated provision for depreciation		742,774			739,719
		1,184,470			1,180,844
Construction work in progress		23,290			18,466
		1,207,760			1,199,310
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		273,627			269,777
Other		1,361			1,362
		274,988			271,139
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		496,129			496,129
Regulatory assets		454,997			409,095
Pension assets		20,928			7,261
Other		41,073			46,354
		1,013,127			958,839
	$	2,764,530		$	2,614,279
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	50,000		$	50,000
Short-term borrowings-
Associated companies		70,120			141,501
Other		222,000			-
Accounts payable-
Associated companies		32,895			100,232
Other		67,427			59,077
Accrued taxes		1,466			11,300
Accrued interest		8,739			7,496
Other		20,415			22,825
		473,062			392,431
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 900,000 shares-
859,000 shares outstanding		1,276,094			1,276,075
Accumulated other comprehensive loss		(27,192	)		(26,516	)
Accumulated deficit		(203,029	)		(234,620	)
Total common stockholder's equity		1,045,873			1,014,939
Long-term debt and other long-term obligations		542,039			542,009
		1,587,912			1,556,948
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		398,561			387,456
Accumulated deferred investment tax credits		9,037			9,244
Nuclear fuel disposal costs		41,983			41,459
Asset retirement obligations		153,469			151,107
Retirement benefits		18,425			19,522
Other		82,081			56,112
		703,556			664,900
COMMITMENTS AND CONTINGENCIES (Note 9)
	$	2,764,530		$	2,614,279

The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these balance sheets.

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31,
	2007			2006
	*(In thousands)*
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	31,639		$	17,914
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		10,284			10,905
Amortization of regulatory assets		34,140			30,048
Deferred costs recoverable as regulatory assets		(19,160	)		(22,818	)
Deferral of new regulatory assets		(42,726	)		-
Deferred income taxes and investment tax credits, net		16,178			1,704
Accrued compensation and retirement benefits		(7,683	)		(3,912	)
Commodity derivative transactions, net		-			(2,148	)
Cash collateral		3,050			-
Pension trust contribution		(11,012	)		-
Decrease (increase) in operating assets-
Receivables		(49,818	)		27,829
Prepayments and other current assets		(27,131	)		(37,665	)
Increase (decrease) in operating liabilities-
Accounts payable		(58,986	)		1,160
Accrued taxes		(9,835	)		(6,080	)
Accrued interest		1,243			(109	)
Other		1,999			(4,649	)
Net cash provided from (used for) operating activities		(127,818	)		12,179

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		150,619			17,065
Net cash provided from financing activities		150,619			17,065

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(18,803	)		(25,277	)
Proceeds from nuclear decommissioning trust fund sales		25,323			42,061
Investments in nuclear decommissioning trust funds		(26,579	)		(44,432	)
Loans to associated companies, net		(2,822	)		(2,145	)
Other		79			549
Net cash used for investing activities		(22,802	)		(29,244	)

Net change in cash and cash equivalents		(1	)		-
Cash and cash equivalents at beginning of period		130			120
Cash and cash equivalents at end of period	$	129		$	120

The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements.

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Metropolitan Edison Company:

We have reviewed the accompanying consolidated balance sheets of Metropolitan Edison Company and its subsidiaries as of March 31, 2007 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(G) and Note 9 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 8, 2007

METROPOLITAN EDISON COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Met-Ed is a wholly owned, electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also provides generation service to those customers electing to retain Met-Ed as their power supplier.

Results of Operations

Net income in the first quarter of 2007 increased to $32 million from $18 million in the first quarter of 2006. This increase was primarily due to higher revenues and deferral of new regulatory assets, partially offset by higher purchased power costs, other operating costs, and amortization of regulatory assets.

Revenues

Revenues increased by $59 million, or 19.0% in the first quarter of 2007 compared with the same period in 2006, reflecting higher retail and wholesale generation revenues. Retail generation revenues increased by $5 million primarily due to higher KWH sales in all customer classes, partially offset by lower composite unit prices in the industrial sector. Residential and commercial revenues increased by $3 million and $2 million, respectively, in the first quarter of 2007 due to higher KWH sales as a result of colder than normal weather compared to unseasonably mild weather during the first quarter of 2006 (heating degree days increased by 15.4% in 2007).

Wholesale revenues increased by $26 million in the first quarter of 2007 compared with the first quarter of 2006 due to Met-Ed selling additional available power into the PJM market beginning in January 2007.

Revenues from distribution throughput increased by $21 million in the first quarter of 2007 due to a 4.0% increase in KWH deliveries reflecting the effect of colder temperatures compared to the same period of 2006, and an increase in composite unit prices resulting from a January 2007 PPUC authorization to recover increased transmission costs.

PJM transmission revenues increased by $7 million in the first quarter of 2007 primarily due to higher transmission volumes and additional PJM auction revenue rights in 2007. Met-Ed defers the difference between revenue accrued under its transmission rider and transmission costs incurred, resulting in no material effect to current period earnings.

Increases in electric generation sales and distribution deliveries in the first quarter of 2007 compared to the same period of 2006 are summarized in the following table:

Changes in KWH Sales

Retail Electric Generation:
Residential	6.4	%
Commercial	3.7	%
Industrial	2.9	%
Total Retail Electric Generation Sales	4.6	%
Distribution Deliveries:
Residential	6.4	%
Commercial	3.5	%
Industrial	1.0	%
Total Distribution Deliveries	4.0	%

Expenses

Total expenses increased by $30 million, or 10.6% in the first quarter of 2007 compared to the first quarter of 2006. The following table presents changes from the prior year by expense category:

Expenses - Changes	Increase (Decrease)
	(In millions)

Purchased power costs	$	32
Other operating costs		37
Provision for depreciation		(1	)
Amortization of regulatory assets		4
Deferral of new regulatory assets		(43	)
General taxes		1
Net increase in expenses	$	30

Purchased power costs increased by $32 million in the first quarter of 2007 as compared with the same period of 2006. The increase was mainly attributable to a 15.8% increase in KWH purchases to meet higher retail and wholesale generation sales. Other operating costs increased by $37 million in the first quarter of 2007 primarily due to higher congestion costs associated with the increased transmission volumes discussed above.

Met-Ed’s revenue in the first quarter of 2007 includes the authorized recovery of transmission costs that were deferred in 2006. As a result, amortization of regulatory assets increased the first quarter of 2007 compared to the prior year. The deferral of new regulatory assets increased in the first quarter of 2007 due to the absence in the first quarter of 2006 of PJM transmission costs and interest deferrals that began in the second quarter of 2006, and the deferral of previously expensed decommissioning costs of $15 million associated with the Saxton nuclear research facility as approved by the PPUC in January 2007.

Capital Resources and Liquidity

During 2007, Met-Ed expects to meet its contractual obligations with a combination of cash from operations and funds from the capital markets. Borrowing capacity under Met-Ed’s credit facilities is available to manage its working capital requirements.

Changes in Cash Position

As of March 31, 2007, Met-Ed had cash and cash equivalents of $129,000 compared with $130,000 as of December 31, 2006. The major sources of changes in these balances are summarized below.

Cash Flows From Operating Activities

Net cash used for operating activities was $128 million in the first quarter of 2007 compared to net cash provided from operating activities of $12 million in the first quarter of 2006, as summarized in the following table:

	Three Months Ended March 31,
Operating Cash Flows	2007			2006
	*(In millions)*
Net income	$	32		$	18
Net non-cash charges (credits)		(9	)		13
Pension trust contribution		(11	)		-
Working capital and other		(140	)		(19	)
Net cash provided from (used for) operating activities	$	(128	)	$	12

Net cash provided from operating activities decreased by $140 million in the first quarter 2007 compared to the same period in 2006. The change was primarily due to a $121 million decrease from changes in working capital and other, a $22 million decrease in non-cash charges and an $11 million pension trust contribution in the first quarter of 2007, partially offset by a $14 million increase in net income. The decrease from working capital primarily resulted from a $78 million change in receivables and a $60 million change in accounts payable, partially offset by an $11 million decrease in prepayments and a $3 million increase in cash collateral received from suppliers. Changes in net income and non-cash charges (credits) are described above under “Results of Operations.”

Cash Flows From Financing Activities

Net cash provided from financing activities was $151 million in the first quarter of 2007 compared to $17 million in the first quarter of 2006. The increase reflects a $134 million increase in short-term borrowings in the first quarter of 2007.

As of March 31, 2007, Met-Ed had approximately $34 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $292 million of short-term borrowings (including $72 million from its receivables financing arrangement). Met-Ed has authorization from the FERC to incur short-term debt up to $250 million (excluding receivables financing) and authorization from the PPUC to incur money pool borrowings up to $300 million.

See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of Met-Ed’s financing capabilities.

Cash Flows From Investing Activities

In the first quarter of 2007, Met-Ed's cash used for investing activities totaled $23 million, compared to $29 million in the first quarter of 2006. The decrease resulted from a $6 million reduction in property additions.

During the remaining three quarters of 2007, capital requirements for property additions and improvements are expected to be approximately $64 million. Met-Ed has cash requirements of approximately $50 million for maturing long-term debt during the remainder of 2007. These cash requirements are expected to be satisfied from a combination of cash from operations, short-term credit arrangements and funds from the capital markets. Met-Ed's capital spending for the period 2007 through 2011 is expected to be about $511 million, of which approximately $83 million applies to 2007.

Market Risk Information

During the first quarter of 2007, net assets for commodity derivative contracts decreased by $5 million as a result of settled contracts ($6 million) and changes in the value of existing contracts ($1 million). These non-trading contracts are adjusted to fair value at the end of each quarter with a corresponding offset to regulatory liabilities, resulting in no impact to current period earnings. Outstanding net assets for commodity derivative contracts were $18 million and $23 million as of March 31, 2007 and December 31, 2006, respectively. See the “Market Risk Information” section of Met-Ed’s 2006 Annual Report on Form 10-K for additional discussion of market risk.

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $165 million and $164 million as of March 31, 2007 and December 31, 2006, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $16 million reduction in fair value as of March 31, 2007.

Regulatory Matters

See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to Met-Ed.

Environmental Matters

See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to Met-Ed.

Other Legal Proceedings

See the “Other Legal Proceedings” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to Met-Ed.

New Accounting Standards and Interpretations

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,
	2007			2006
	*(In thousands)*

REVENUES:
Electric sales	$	339,226		$	275,827
Gross receipts tax collections		16,680			15,925
Total revenues		355,906			291,752

EXPENSES:
Purchased power		200,842			161,641
Other operating costs		59,461			38,342
Provision for depreciation		11,777			12,643
Amortization of regulatory assets		15,394			14,815
Deferral of new regulatory assets		(17,088	)		-
General taxes		19,851			19,389
Total expenses		290,237			246,830

OPERATING INCOME		65,669			44,922

OTHER INCOME (EXPENSE):
Miscellaneous income		1,417			2,370
Interest expense		(11,337	)		(10,536	)
Capitalized interest		258			347
Total other expense		(9,662	)		(7,819	)

INCOME BEFORE INCOME TAXES		56,007			37,103

INCOME TAXES		24,263			13,954

NET INCOME		31,744			23,149

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(2,825	)		-
Unrealized gain on derivative hedges		16			16
Unrealized loss on available for sale securities		(3	)		(4	)
Other comprehensive income (loss)		(2,812	)		12
Income tax expense (benefit) related to other
comprehensive income		(1,298	)		6
Other comprehensive income (loss), net of tax		(1,514	)		6

TOTAL COMPREHENSIVE INCOME	$	30,230		$	23,155

The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements.

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
	March 31,			December 31,
	2007			2006
	*(In thousands)*
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	42		$	44
Receivables-
Customers (less accumulated provisions of $3,845,000 and $3,814,000
respectively, for uncollectible accounts)		147,874			126,639
Associated companies		47,552			49,728
Other		32,057			16,367
Notes receivable from associated companies		18,840			19,548
Prepaid gross receipts taxes		39,502			1,917
Prepayments and other		959			2,319
		286,826			216,562
UTILITY PLANT:
In service		2,149,976			2,141,324
Less - Accumulated provision for depreciation		813,112			809,028
		1,336,864			1,332,296
Construction work in progress		26,964			22,124
		1,363,828			1,354,420
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		127,014			125,216
Non-utility generation trusts		100,514			99,814
Other		531			531
		228,059			225,561
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		860,716			860,716
Pension assets		28,101			11,474
Other		33,129			36,059
		921,946			908,249
	$	2,800,659		$	2,704,792
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Short-term borrowings-
Associated companies	$	94,592		$	199,231
Other		224,000			-
Accounts payable-
Associated companies		40,112			92,020
Other		53,369			47,629
Accrued taxes		2,518			11,670
Accrued interest		12,742			7,224
Other		19,522			21,178
		446,855			378,952
CAPITALIZATION:
Common stockholder's equity-
Common stock, $20 par value, authorized 5,400,000 shares-
5,290,596 shares outstanding		105,812			105,812
Other paid-in capital		1,189,453			1,189,434
Accumulated other comprehensive loss		(8,707	)		(7,193	)
Retained earnings		121,702			90,005
Total common stockholder's equity		1,408,260			1,378,058
Long-term debt and other long-term obligations		477,504			477,304
		1,885,764			1,855,362
NONCURRENT LIABILITIES:
Regulatory liabilities		69,668			96,151
Asset retirement obligations		78,126			76,924
Accumulated deferred income taxes		190,513			193,662
Retirement benefits		50,662			50,328
Other		79,071			53,413
		468,040			470,478
COMMITMENTS AND CONTINGENCIES (Note 9)
	$	2,800,659		$	2,704,792

The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these balance sheets.

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31,
	2007			2006
	*(In thousands)*
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	31,744		$	23,149
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		11,777			12,643
Amortization of regulatory assets		15,394			14,815
Deferral of new regulatory assets		(17,088	)		-
Deferred costs recoverable as regulatory assets		(18,433	)		(19,211	)
Deferred income taxes and investment tax credits, net		13,366			5,361
Accrued compensation and retirement benefits		(8,786	)		(472	)
Cash collateral		1,450			-
Commodity derivative transactions, net		-			(4,206	)
Pension trust contribution		(13,436	)		-
Decrease (Increase) in operating assets-
Receivables		(30,050	)		16,729
Prepayments and other current assets		(36,225	)		(36,540	)
Increase (Decrease) in operating liabilities-
Accounts payable		(46,168	)		(9,623	)
Accrued taxes		(9,152	)		(4,904	)
Accrued interest		5,518			5,401
Other		1,943			(6,745	)
Net cash used for operating activities		(98,146	)		(3,603	)

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		119,361			39,315
Net cash provided from financing activities		119,361			39,315

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(20,404	)		(35,610	)
Loan repayments from (loans to) associated companies, net		708			(1,134	)
Proceeds from nuclear decommissioning trust fund sales		9,758			14,942
Investments in nuclear decommissioning trust funds		(10,532	)		(14,942	)
Other, net		(747	)		1,032
Net cash used for investing activities		(21,217	)		(35,712	)

Net change in cash and cash equivalents		(2	)		-
Cash and cash equivalents at beginning of period		44			35
Cash and cash equivalents at end of period	$	42		$	35

The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements.

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Pennsylvania Electric Company:

We have reviewed the accompanying consolidated balance sheets of Pennsylvania Electric Company and its subsidiaries as of March 31, 2007 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(G) and Note 9 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 8, 2007

100

PENNSYLVANIA ELECTRIC COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern, western and south central Pennsylvania, providing regulated transmission and distribution services. Penelec also provides generation services to those customers electing to retain Penelec as their power supplier.

Results of Operations

Net income in the first quarter of 2007 increased to $32 million, compared to $23 million in the first quarter of 2006. This increase resulted from higher revenues and the deferral of new regulatory assets, partially offset by higher purchased power costs and other operating costs.

Revenues

Revenues increased by $64 million in the first quarter of 2007 compared to the same period of 2006, reflecting higher retail and wholesale generation revenues. Retail generation revenues increased by $6 million in the first quarter of 2007 primarily due to higher KWH sales in all customer classes, partially offset by lower composite unit prices in the industrial sector. Residential and commercial sales both increased by $3 million for the first quarter of 2007 due to increases in KWH sales as a result of colder than normal weather compared to unseasonably mild weather during the first quarter of 2006 (heating degree days increased by 14.2% in 2007).

Wholesale revenues increased $36 million in the first quarter of 2007 compared with the first quarter of 2006 due to Penelec selling additional available power into the PJM market beginning in January 2007.

Revenues from distribution throughput increased $16 million in the first quarter of 2007 due to a 3.0% increase in KWH deliveries reflecting the effect of colder temperatures compared to the same period of 2006, and an increase in composite unit prices resulting from a January 2007 PPUC authorization to recover increased transmission costs.

PJM transmission revenues increased by $6 million in the first quarter of 2007 compared to the same period in 2006 due to higher transmission volumes and additional PJM auction revenue rights in 2007. Penelec defers the difference between revenue accrued under its transmission rider and transmission costs incurred, with no material effect to current period earnings.

Changes in electric generation sales and distribution deliveries in the first quarter of 2007 compared to the same period of 2006 are summarized in the following table:


Changes in KWH Sales
Increase (Decrease)
Retail Electric Generation:
Residential	5.7	%
Commercial	5.0	%
Industrial	0.1	%
Total Retail Electric Generation Sales	3.8	%

Distribution Deliveries:
Residential	5.7	%
Commercial	5.0	%
Industrial	(1.8	)%
Total Distribution Deliveries	3.0	%

101

Expenses

Total expenses increased by $44 million or 17.6% in the first quarter of 2007 compared to the first quarter of 2006. The following table presents changes from the prior year by expense category:

	Increase
Expenses - Changes	(Decrease)
	*(In millions)*
Increase (Decrease)
Purchased power costs	$	39
Other operating costs		21
Provision for depreciation		(1	)
Amortization of regulatory assets		1
Deferral of new regulatory assets		(17	)
General taxes		1
Net increase in expenses	$	44

Purchased power costs increased by $39 million or 24.3% in the first quarter of 2007, compared to the same period of 2006. The increase was due primarily to an increase in KWH purchases to meet the increased retail and wholesale generation sales and a 2.4% increase in composite unit prices. Other operating costs increased by $21 million in the first quarter of 2007 principally due to higher congestion costs associated with the increased transmission volumes discussed above.

Penelec’s revenue in the first quarter of 2007 includes the authorized recovery of transmission costs that were deferred in 2006. As a result, amortization of regulatory assets increased in the first quarter of 2007 compared to the prior year. The deferral of new regulatory assets increased in the first quarter of 2007 due to the absence in the first quarter of 2006 of PJM transmission costs and interest deferrals that began in the second quarter of 2006 and the deferral of previously expensed decommissioning costs of $12 million associated with the Saxton nuclear research facility as approved by the PPUC in January 2007.

Capital Resources and Liquidity

During 2007, Penelec expects to meet its contractual obligations with a combination of cash from operations and funds from the capital markets. Borrowing capacity under Penelec’s credit facilities is available to manage its working capital requirements.

Changes in Cash Position

As of March 31, 2007, Penelec had $42,000 of cash and cash equivalents compared with $44,000 as of December 31, 2006. The major sources of changes in these balances are summarized below.

Cash Flows From Operating Activities

Net cash used for operating activities in the first quarter of 2007 and 2006 were as follows:

	Three Months Ended
	March 31,
Operating Cash Flows	2007			2006
	*(In millions)*

Net income	$	32		$	23
Net non-cash charges (credits)		(4	)		9
Pension trust contribution		(13	)		-
Working capital and other		(113	)		(36	)
Net cash used for operating activities	$	(98	)	$	(4	)

Net cash used for operating activities increased $94 million in the first quarter of 2007 compared to the first quarter of 2006 as a result of a $77 million change in working capital and other, a $13 million pension trust contribution in the first quarter of 2007 and a $13 million decrease in net non-cash charges, partially offset by a $9 million increase in net income. The $77 million decrease from working capital was principally due to changes in receivables of $47 million and changes in accounts payable of $37 million. Changes in net income and non-cash charges are described above under “Results of Operations.”

102

Cash Flows From Financing Activities

Net cash provided from financing activities increased $80 million in the first quarter of 2007 compared to the first quarter of 2006. The change reflects an increase in short-term borrowings.

Penelec had approximately $19 million of cash and temporary investments (which includes short-term notes receivable from associated companies) and approximately $319 million of short-term indebtedness (including $74 million from its receivables financing arrangement) as of March 31, 2007. Penelec has authorization from the FERC to incur short-term debt of up to $250 million (excluding receivables financing) and authorization from the PPUC to incur money pool borrowings of up to $300 million.

See the “Financing Capability” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for additional discussion of Penelec’s financing capabilities.

Cash Flows From Investing Activities

In the first quarter of 2007, net cash used for investing activities totaled $21 million compared to $36 million in the first quarter of 2006. The decrease primarily resulted from a $15 million reduction in property additions.

During the remaining three quarters of 2007, capital requirements for property additions are expected to be approximately $71 million. These cash requirements are expected to be satisfied from a combination of cash from operations, short-term credit arrangements and funds from the capital markets. Penelec’s capital spending for the period 2007-2011 is expected to be approximately $614 million, of which approximately $92 million applies to 2007.

Market Risk Information

During the first quarter of 2007, net assets for commodity derivative contracts decreased by $2 million as a result of settled contracts. These non-trading contracts are adjusted to fair value at the end of each quarter with a corresponding offset to regulatory liabilities, resulting in no impact to current period earnings. Outstanding net assets for commodity derivative contracts were $10 million and $12 million as of March 31, 2007 and December 31, 2006, respectively. See the “Market Risk Information” section of Penelec’s 2006 Annual Report on Form 10-K for additional discussion of market risk.

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $73 million and $72 million as of March 31, 2007 and December 31, 2006, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $7 million reduction in fair value as of March 31, 2007.

Regulatory Matters

See the “Regulatory Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of regulatory matters applicable to Penelec.

Environmental Matters

See the “Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of environmental matters applicable to Penelec.

Other Legal Proceedings

See the “Other Legal Proceedings” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to Penelec.

New Accounting Standards and Interpretations

103

COMBINED MANAGEMENT’S DISCUSSION

AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain disclosures referenced in Management’s Discussion and Analysis of Financial Condition and Results of Operations of the Companies. This information should be read in conjunction with (i) the Companies’ respective Consolidated Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operations; (ii) the Notes to Consolidated Financial Statements as they relate to the Companies; and (iii) the Companies’ respective 2006 Annual Reports on Form 10-K.

Financing Capability (Applicable to each of the Companies)

As of March 31, 2007, OE, CEI and TE had the capability to issue approximately $1.5 billion, $536 million and $789 million, respectively, of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE, CEI and TE is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE, CEI and TE to incur additional secured debt not otherwise permitted by a specified exception of up to $600 million, $517 million and $130 million, respectively, as of March 31, 2007. Under the provisions of its senior note indenture, JCP&L may issue additional FMB only as collateral for senior notes. As of March 31, 2007, JCP&L had the capability to issue $937 million of additional senior notes upon the basis of FMB collateral.

As of March 31, 2007, OE had approximately $400 million of capacity remaining unused under its existing shelf registration for unsecured debt securities filed with the SEC in 2006.

On August 24, 2006, FirstEnergy and certain of its subsidiaries entered into a $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 this facility up to a maximum of $3.25 billion. Commitments under the 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.

	Revolving				Regulatory and
	Credit Facility				Other Short-Term
Borrower	Sub-Limit				Debt Limitations⁽¹⁾
	*(In millions)*
FirstEnergy		$	2,750			$	1,500
OE		500				500
Penn		50				39
CEI		250		⁽²⁾		500
TE		250		⁽²⁾		500
JCP&L		425				412
Met-Ed		250				250		⁽³⁾
Penelec		250				250		⁽³⁾

⁽¹⁾ As of March 31, 2007.

⁽²⁾

Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice to the

administrative agent that such borrower has senior unsecured debt ratings of at least BBB by S&P and

Baa2 by Moody’s.

⁽³⁾ Excluding amounts which may be borrowed under the regulated money pool.

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Borrower
FirstEnergy	61	%
OE	49	%
Penn	28	%
CEI	57	%
TE	49	%
JCP&L	25	%
Met-Ed	46	%
Penelec	36	%

The Companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. FESC administers the regulated money pool and tracks surplus funds of FirstEnergy and the respective Companies, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreement 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 and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first quarter of 2007 was approximately 5.61%.

Issuer	Securities	S&P	Moody’s	Fitch

FirstEnergy	Senior unsecured	BBB-	Baa3	BBB

OE	Senior unsecured	BBB-	Baa2	BBB

CEI	Senior secured	BBB	Baa2	BBB
	Senior unsecured	BBB-	Baa3	BBB-

TE	Senior secured	BBB	Baa2	BBB
	Senior unsecured	BBB-	Baa3	BBB-

Penn	Senior secured	BBB+	Baa1	BBB+

JCP&L	Senior secured	BBB+	Baa1	A-

Met-Ed	Senior unsecured	BBB	Baa2	BBB

Penelec	Senior unsecured	BBB	Baa2	BBB

OE, CEI, Penn, Met-Ed and Penelec each have a wholly owned subsidiary whose borrowings are secured by customer accounts receivable purchased from its respective parent company. The CEI subsidiary's borrowings are also secured by customer accounts receivable purchased from TE. Each subsidiary company has its own receivables financing arrangement and, as a separate legal entity with separate creditors, would have to satisfy its obligations to creditors before any of its remaining assets could be available to its parent company. The receivables financing borrowing capacity and outstanding balance by company, as of March 31, 2007, are shown in the following table.

Subsidiary Company	Parent Company		Borrowing Capacity		Outstanding Balance	Annual Facility Fee
	*(In millions)*
OES Capital, Incorporated	OE	$	170	$	156	0.15%
Centerior Funding Corp.	CEI		200		-	0.15
Penn Power Funding LLC	Penn		25		19	0.125
Met-Ed Funding LLC	Met-Ed		80		72	0.125
Penelec Funding LLC	Penelec		75		74	0.125
		$	550	$	321

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Regulatory Matters (Applicable to each of the Companies)

·	restructuring the electric generation business and allowing customers to select a competitive electric generation supplier other than the Companies;

·	establishing or defining the PLR obligations to customers in the Companies' service areas;

·	providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market;

·	itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges;

·	continuing regulation of the Companies' transmission and distribution systems; and

·	requiring corporate separation of regulated and unregulated business activities.

The Companies recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. The following table discloses regulatory assets by company:

	March 31,		December 31,		Increase
Regulatory Assets*	2007		2006		(Decrease)
	*(In millions)*
OE	$	729	$	741	$	(12	)
CEI		854		855		(1	)
TE		237		248		(11	)
JCP&L		2,059		2,152		(93	)
Met-Ed		455		409		46
Total	$	4,334	$	4,405	$	(71	)

*	Penelec had net regulatory liabilities of approximately $70 million and $96 million as of March 31, 2007 and December 31, 2006, respectively. These net regulatory liabilities are included in Other Non-current Liabilities on the Consolidated Balance Sheets.

Ohio (Applicable to OE, CEI and TE)

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

106

Amortization							Total
Period	OE		CEI		TE		Ohio
	*(In millions)*
2007	$	179	$	108	$	93	$	380
2008		208		124		119		451
2009		-		216		-		216
2010		-		273		-		273
Total Amortization	$	387	$	721	$	212	$	1,320

Pennsylvania (Applicable to Met-Ed, Penelec and Penn)

107

The PPUC entered its Opinion and Order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, when new transmission rates were effective, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes in NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission expenses and the transmission deferral. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million). Met-Ed and Penelec filed a Petition for Reconsideration on January 26, 2007 on the issues of consolidated tax savings and rate of return on equity. Other parties filed Petitions for Reconsideration on transmission (including congestion), transmission deferrals and rate design issues. On February 8, 2007, the PPUC entered an order granting Met-Ed’s, Penelec’s and the other parties’ petitions for procedural purposes. Due to that ruling, the period for appeals to the Commonwealth Court was tolled until 30 days after the PPUC entered a subsequent order ruling on the substantive issues raised in the petitions. On March 1, 2007, the PPUC issued three orders: 1) a tentative order regarding the reconsideration by the PPUC of its own order; 2) an order denying the Petitions for Reconsideration of Met-Ed, Penelec and the OCA and denying in part and accepting in part MEIUG’s and PICA’s Petition for Reconsideration; and 3) an order approving the Compliance filing. Comments to the PPUC for reconsideration of its order were filed on March 8, 2007, and the PPUC ruled on the reconsideration on April 13, 2007, making minor changes to rate design as agreed upon by Met-Ed, Penelec and certain other parties.

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On May 2, 2007, Penn filed a plan with the PPUC for the procurement of PLR supply from June 2008 through May 2011. The filing proposes multiple, competitive RFPs with staggered delivery periods for fixed-price, tranche-based, pay as bid PLR supply to the residential and commercial classes. The proposal phases out existing promotional rates and eliminates the declining block and the demand components on generation rates for residential and commercial customers. The industrial class PLR service would be provided through an hourly-priced service provided by Penn. Quarterly reconciliation of the differences between the costs of supply and revenues from customers is also proposed. The PPUC is requested to act on the proposal no later than November 2007 for the initial RFP to take place in January 2008.

New Jersey (Applicable to JCP&L)

As a result of outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L’s service reliability. In 2004, the NJBPU adopted an MOU that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L’s ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a Stipulation that incorporates the final report of an SRM who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The Stipulation also incorporates the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L’s Planning and Operations and Maintenance programs and practices (Focused Audit). On February 11, 2005, JCP&L met with the DRA to discuss reliability improvements. The SRM completed his work and issued his final report to the NJBPU on June 1, 2006. JCP&L filed a comprehensive response to the NJBPU on July 14, 2006. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.

109

In October 2006, the current EMP process was initiated with the issuance of a proposed set of objectives which, as to electricity, included the following:

·	Reduce the total projected electricity demand by 20% by 2020;

·	Meet 22.5% of New Jersey’s electricity needs with renewable energy resources by that date;

·	Reduce air pollution related to energy use;

·	Encourage and maintain economic growth and development;

·	Achieve a 20% reduction in both Customer Average Interruption Duration Index and System Average Interruption Frequency Index by 2020;

·	Unit prices for electricity should remain no more than +5% of the regional average price (region includes New York, New Jersey, Pennsylvania, Delaware, Maryland and the District of Columbia); and

·	Eliminate transmission congestion by 2020.

FERC Matters (Applicable to each of the Companies)

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 the 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. JCP&L, Met-Ed and Penelec 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 the second quarter of 2007.

110

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. MISO and PJM will be filing revised tariffs to comply with FERC’s order.

Environmental Matters (Applicable to each of the Companies)

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

111

Regulation of Hazardous Waste

W. H. Sammis Plant (Applicable to OE and Penn)

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 FES 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, FirstEnergy 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 for FGCO ($400 million of which is expected to be spent during 2007, with the largest portion of the remaining $1.1 billion expected to be spent in 2008 and 2009).

Other Legal Proceedings (Applicable to each of the Companies)

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

Power Outages and Related Litigation

112

113

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

Other Legal Matters

On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members. On April 5, 2007, the Court rejected the plaintiffs’ request to certify this case as a class action and, accordingly, did not appoint the plaintiffs as class representatives or their counsel as class counsel. The Court has scheduled oral argument for June 25, 2007 to hear the plaintiffs' request for reconsideration of its order denying class certification and request to amend their complaint.

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. JCP&L intends to re-file an appeal in federal district court once the damages associated with this case are identified at an individual employee level. JCP&L recognized a liability for the potential $16 million award in 2005.

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

New Accounting Standards and Interpretations (Applicable to each of the Companies)

SFAS 159 - “The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB

Statement No. 115”

In February 2007, the 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 and SFAS 107. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. The Companies are currently evaluating the impact of this Statement on their respective financial statements.

114

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 Companies are currently evaluating the impact of this Statement on their respective financial statements.

EITF 06-10 - “Accounting for Deferred Compensation and Postretirement Benefit Aspects of Collateral

Split-Dollar Life Insurance Arrangements”

In March 2007, the EITF reached a final consensus on Issue 06-10 concluding that an employer should recognize a liability for the postretirement obligation associated with a collateral assignment split-dollar life insurance arrangement if, based on the substantive arrangement with the employee, the employer has agreed to maintain a life insurance policy during the employee’s retirement or provide the employee with a death benefit. The liability should be recognized in accordance with SFAS 106 if, in substance, a postretirement plan exists or APB 12 if the arrangement is, in substance, an individual deferred compensation contract. The EITF also reached a consensus that the employer should recognize and measure the associated asset on the basis of the terms of the collateral assignment arrangement. This pronouncement is effective for fiscal years beginning after December 15, 2007, including interim periods within those years. The Companies do not expect this pronouncement to have a material impact on their respective financial statements.

115

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Market Risk Information” in Item 2 above.

ITEM 4. CONTROLS AND PROCEDURES

(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

The applicable registrant's chief executive officer and chief financial officer have reviewed and evaluated the registrant's disclosure controls and procedures. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, those officers have concluded that the applicable registrant's disclosure controls and procedures are effective and were designed to bring to their attention material information relating to the registrant and its consolidated subsidiaries by others within those entities.

(b) CHANGES IN INTERNAL CONTROLS

During the quarter ended March 31, 2007, there were no changes in the registrants' internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting

116

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 9 and 10 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 1A. RISK FACTORS

See Item 1A RISK FACTORS in Part I of the Form 10-K for the year ended December 31, 2006 for a discussion of the risk factors of FirstEnergy and the subsidiary registrants. For the quarter ended March 31, 2007, there have been no material changes to these risk factors.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

(c) FirstEnergy

The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock.

	Period
	January 1-31,	February 1-28,	March 1-31,	First
	2007	2007	2007	Quarter
Total Number of Shares Purchased ^(a)	62,469	226,418	15,272,836	15,561,723
Average Price Paid per Share	$59.61	$63.78	$62.69	$62.69
Total Number of Shares Purchased
As Part of Publicly Announced Plans
or Programs ^(b)	-	-	14,370,110	14,370,110
Maximum Number (or Approximate Dollar
Value) of Shares that May Yet Be
Purchased Under the Plans or Programs	16,000,000	16,000,000	1,629,890	1,629,890

^(a)	Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock under its Executive and Director Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the Executive and Director Incentive Compensation Plan and shares purchased as part of publicly announced plans.

^(b)	FirstEnergy publicly announced, on January 30, 2007, a plan to repurchase up to 16 million shares of its common stock through June 30, 2008. On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding common stock under this plan through an accelerated share repurchase program with an affiliate of Morgan Stanley and Co., Incorporated at an initial price of $62.63 per share.

ITEM 6. EXHIBITS

Exhibit Number
Exhibit Number

FirstEnergy

	10.1	Confirmation dated March 1, 2007 between FirstEnergy Corp. and Morgan Stanley and Co., International Limited ⁽¹⁾
	10.2	Form of U.S. $250,000,000 Credit Agreement, dated as of March 2, 2007, between FirstEnergy Corp., as Borrower, and Morgan Stanley Senior Funding, Inc., as Lender. ⁽²⁾
	10.3	Form of Guaranty dated as of March 2, 2007, between FirstEnergy Corp., as Guarantor, and Morgan Stanley Senior Funding, Inc., as Lender under a U.S. $250,000,000 Credit Agreement, dated as of March 2, 2007, with FirstEnergy Solutions Corp., as Borrower.
	12	Fixed charge ratios
	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

117

OE

	12	Fixed charge ratios
	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

CEI

	4	Officer’s Certificate (including the form of 5.70% Senior Notes due 2017), dated as of March 27, 2007(Form 8-K dated March 28, 2007, Exhibit 4).
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

TE

	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

JCP&L

	12	Fixed charge ratios
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

Met-Ed

	12	Fixed charge ratios
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

Penelec

	12	Fixed charge ratios
	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

⁽¹⁾	Confidential treatment has been requested for certain portions of the Exhibit. Omitted portions have been filed separately with the SEC.

⁽²⁾

A substantially similar agreement, dated as of the same date and in the same amount, was executed and delivered by

the registrant’s subsidiary, FirstEnergy Solutions Corp., for which the registrant provided its guaranty in the form filed as

Exhibit 10.2 above, all as described in the registrant’s Form 8-K filed March 5, 2007.

Pursuant to reporting requirements of respective financings, FirstEnergy, OE, JCP&L, Met-Ed and Penelec are required to file fixed charge ratios as an exhibit to this Form 10-Q.

Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, OE, CEI, TE, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but each hereby agrees to furnish to the SEC on request any such documents.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

May 9, 2007

	FIRSTENERGY CORP.
	Registrant

	OHIO EDISON COMPANY
	Registrant

	THE CLEVELAND ELECTRIC
	ILLUMINATING COMPANY
	Registrant

	THE TOLEDO EDISON COMPANY
	Registrant

	JERSEY CENTRAL POWER & LIGHT COMPANY
	Registrant

	METROPOLITAN EDISON COMPANY
	Registrant

	PENNSYLVANIA ELECTRIC COMPANY
	Registrant

	/s/ Harvey L. Wagner
	Harvey L. Wagner
	Vice President, Controller
	and Chief Accounting Officer

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