FirstEnergy (FE) 10-Q 2008 Q2 Quarterly report

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 June 30, 2008

OR

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

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

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
333-145140-01	FIRSTENERGY SOLUTIONS CORP.	31-1560186
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	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 the registrant (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 (  )	FirstEnergy Corp., Ohio Edison Company and Pennsylvania Electric Company
Yes (  )  No (X)	FirstEnergy Solutions Corp., The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company and Metropolitan Edison Company

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

Large Accelerated Filer (X)	FirstEnergy Corp.
Accelerated Filer (  )	N/A
Non-accelerated Filer (Do not check if a smaller reporting company) (X)	FirstEnergy Solutions 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

Smaller Reporting Company (  ) N/A

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

Yes (  ) No (X) FirstEnergy Corp., FirstEnergy Solutions 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

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 AUGUST 6, 2008
FirstEnergy Corp., $0.10 par value	304,835,407
FirstEnergy Solutions Corp., no par value	7
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	14,421,637
Metropolitan Edison Company, no par value	859,500
Pennsylvania Electric Company, $20 par value	4,427,577

FirstEnergy Corp. is the sole holder of FirstEnergy Solutions 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 common stock.

This combined Form 10-Q is separately filed by FirstEnergy Corp., FirstEnergy Solutions 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.

OMISSION OF CERTAIN INFORMATION

FirstEnergy Solutions 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 meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.

Forward-Looking Statements: 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 include declarations regarding management’s intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “believe,” “estimate” and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievement expressed or implied by such forward-looking statements.

Actual results may differ materially due to:

·   the speed and nature of increased competition in the electric utility industry and legislative and regulatory changes affecting how generation rates will be determined following the expiration of existing rate plans in Ohio and Pennsylvania,

·   the impact of the PUCO’s rulemaking process on the Ohio Companies’ ESP and MRO filings,

·   economic or weather conditions affecting future sales and margins,

·   changes in markets for energy services,

·   changing energy and commodity market prices and availability,

·   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,

·   other legislative and regulatory changes, revised environmental requirements, including possible GHG emission regulations,

·   the impact of the U.S. Court of Appeals’ July 11, 2008 decision to vacate the CAIR rules and the scope of any laws, rules or regulations that may ultimately take their place,

·   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 NSR litigation or other potential regulatory initiatives,

·   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 (including, but not limited to, the Demand for Information issued to FENOC on May 14, 2007),

·   the timing and outcome of various proceedings before the

-   PUCO (including, but not limited to, the distribution rate cases and the generation supply plan filing for the Ohio Companies and the successful resolution of the issues remanded to the PUCO by the Ohio Supreme Court regarding the RSP and RCP, including the deferral of fuel costs)

-   and Met-Ed’s and Penelec’s transmission service charge filings with the PPUC as well as the resolution of the Petitions for Review filed with the Commonwealth Court of Pennsylvania with respect to the transition rate plan for Met-Ed and Penelec,

·   the continuing availability of generating units and their ability to operate at, or near full capacity,

·   the changing market conditions that could affect the value of assets held in the registrants’ nuclear decommissioning trusts, pension trusts and other trust funds,

·   the ability to comply with applicable state and federal reliability standards,

·   the ability to accomplish or realize anticipated benefits from strategic goals (including employee workforce initiatives),

·   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 risks and other factors discussed from time to time in the registrants’ SEC filings, and other similar factors.

The foregoing review of factors should not be construed as exhaustive. New factors emerge from time to time, and it is not possible to predict all such factors, nor assess the impact of any such factor on the registrants’ business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. 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 ofFinancial Condition and Results of Operations.
FirstEnergy Corp.
	Management's Discussion and Analysis of Financial Condition and
	Results of Operations	1-42
	Report of Independent Registered Public Accounting Firm	43
	Consolidated Statements of Income	44
	Consolidated Statements of Comprehensive Income	45
	Consolidated Balance Sheets	46
	Consolidated Statements of Cash Flows	47
FirstEnergy Solutions Corp.
	Management's Narrative Analysis of Results of Operations	48-50
	Report of Independent Registered Public Accounting Firm	51
	Consolidated Statements of Income and Comprehensive Income	52
	Consolidated Balance Sheets	53
	Consolidated Statements of Cash Flows	54
Ohio Edison Company
	Management's Narrative Analysis of Results of Operations	55-56
	Report of Independent Registered Public Accounting Firm	57
	Consolidated Statements of Income and Comprehensive Income	58
	Consolidated Balance Sheets	59
	Consolidated Statements of Cash Flows	60
The Cleveland Electric Illuminating Company
	Management's Narrative Analysis of Results of Operations	61-62
	Report of Independent Registered Public Accounting Firm	63
	Consolidated Statements of Income and Comprehensive Income	64
	Consolidated Balance Sheets	65
	Consolidated Statements of Cash Flows	66
The Toledo Edison Company
	Management's Narrative Analysis of Results of Operations	67-68
	Report of Independent Registered Public Accounting Firm	69
	Consolidated Statements of Income and Comprehensive Income	70
	Consolidated Balance Sheets	71
	Consolidated Statements of Cash Flows	72

i

TABLE OF CONTENTS (Cont'd)

Jersey Central Power & Light Company		Pages
	Management's Narrative Analysis of Results of Operations	73-74
	Report of Independent Registered Public Accounting Firm	75
	Consolidated Statements of Income and Comprehensive Income	76
	Consolidated Balance Sheets	77
	Consolidated Statements of Cash Flows	78
Metropolitan Edison Company
	Management's Narrative Analysis of Results of Operations	79-80
	Report of Independent Registered Public Accounting Firm	81
	Consolidated Statements of Income and Comprehensive Income	82
	Consolidated Balance Sheets	83
	Consolidated Statements of Cash Flows	84
Pennsylvania Electric Company
	Management's Narrative Analysis of Results of Operations	85-86
	Report of Independent Registered Public Accounting Firm	87
	Consolidated Statements of Income and Comprehensive Income	88
	Consolidated Balance Sheets	89
	Consolidated Statements of Cash Flows	90
Combined Management’s Discussion and Analysis of Registrant Subsidiaries		91-106
Combined Notes to Consolidated Financial Statements		107-140
Item 3.       Quantitative and Qualitative Disclosures About Market Risk.		141
Item 4.       Controls and Procedures – FirstEnergy.		141
Item 4T.     Controls and Procedures – FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec.		141
Part II.    Other Information
Item 1.       Legal Proceedings.		142
Item 1A.    Risk Factors.		142
Item 2.       Unregistered Sales of Equity Securities and Use of Proceeds.		142
Item 4.       Submission of Matters to a Vote of Security Holders.		143-144
Item 5.       Other Information.		144
Item 6.       Exhibits.		144-145

ii

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, Incorporated, owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
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
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
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
Pennsylvania Companies	Met-Ed, Penelec and Penn
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
The following abbreviations and acronyms are used to identify frequently used terms in this report:
ACO	Administrative Consent Order
AEP	American Electric Power Company, Inc.
ALJ	Administrative Law Judge
AMP-Ohio	American Municipal Power-Ohio, Inc.
AOCL	Accumulated Other Comprehensive Loss
AQC	Air Quality Control
ARB	Accounting Research Bulletin
ARO	Asset Retirement Obligation
ASM	Ancillary Services Market
BGS	Basic Generation Service
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CBP	Competitive Bid Process
CO2	Carbon Dioxide
DFI	Demand for Information
DOJ	United States Department of Justice
DRA	Division of Ratepayer Advocate
EIS	Energy Independence Strategy
EITF	Emerging Issues Task Force
EMP	Energy Master Plan
EPA	United States Environmental Protection Agency
EPACT	Energy Policy Act of 2005
ESP	Electric Security Plan
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
FIN 46R	FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities"
FIN 47	FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"
FIN 48	FIN 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109”

iii

GLOSSARY OF TERMS, Cont’d.

FMB	First Mortgage Bonds
FSP	FASB Staff Position
FSP FAS 157-2	FSP FAS 157-2, “Effective Date of  FASB Statement No. 157”
FTR	Financial Transmission Rights
GAAP	Accounting Principles Generally Accepted in the United States
GHG	Greenhouse Gases
ICE	Intercontinental Exchange
IRS	Internal Revenue Service
ISO	Independent System Operator
kV	Kilovolt
KWH	Kilowatt-hours
LIBOR	London Interbank Offered Rate
LOC	Letter of Credit
MEIUG	Met-Ed Industrial Users Group
MEW	Mission Energy Westside, Inc.
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service
MRO	Market Rate Offer
MW	Megawatts
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NJBPU	New Jersey Board of Public Utilities
NOPR	Notice of Proposed Rulemaking
NOV	Notice of Violation
NOX	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
NSR	New Source Review
NUG	Non-Utility Generation
NUGC	Non-Utility Generation Charge
NYMEX	New York Mercantile Exchange
OCA	Office of Consumer Advocate
OTC	Over the Counter
OVEC	Ohio Valley Electric Corporation
PCAOB	Public Company Accounting Oversight Board
PCRB	Pollution Control Revenue Bond
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 Agreement
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act of 1935
RCP	Rate Certainty Plan
RECB	Regional Expansion Criteria and Benefits
RFP	Request for Proposal
RPM	Reliability Pricing Model
RSP	Rate Stabilization Plan
RTC	Regulatory Transition Charge
RTO	Regional Transmission Organization
S&P	Standard & Poor’s Ratings Service
SB221	Amended Substitute Senate Bill 221
SBC	Societal Benefits Charge
SEC	U.S. Securities and Exchange Commission
SECA	Seams Elimination Cost Adjustment
SFAS	Statement of Financial Accounting Standards
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 141(R)	SFAS No 141(R), “Business Combinations”
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”

iv

GLOSSARY OF TERMS, Cont’d.

SFAS 160	SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51”
SFAS 161	SFAS No 161, “Disclosure about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133”
SFAS 162	SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles”
SIP	State Implementation Plan(s) Under the Clean Air Act
SNCR	Selective Non-Catalytic Reduction
SO2	Sulfur Dioxide
TBC	Transition Bond Charge
TMI-1	Three Mile Island Unit 1
TMI-2	Three Mile Island Unit 2
TSC	Transmission Service Charge
VIE	Variable Interest Entity

v

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.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EXECUTIVE SUMMARY

Net income in the second quarter of 2008 was $263 million, or basic earnings of $0.86 per share of common stock ($0.85 diluted), compared with net income of $338 million, or basic earnings of $1.11 per share of common stock ($1.10 diluted) in the second quarter of 2007. Net income in the first six months of 2008 was $539million, or basic earnings of $1.77per share of common stock ($1.75diluted), compared with net income of $628 million, or basic earnings of $2.03 per share of common stock ($2.01 diluted) in the first six months of 2007.

Change in Basic Earnings Per Share From Prior Year Periods	Three Months Ended June 30			Six Months Ended June 30
Basic Earnings Per Share – 2007	$	1.11		$	2.03
Gain on non-core asset sales – 2008		-			0.06
Litigation settlement – 2008		0.03			0.03
Saxton decommissioning regulatory asset – 2007		-			(0.05	)
Trust securities impairment		(0.02	)		(0.04	)
Revenues		0.24			0.79
Fuel and purchased power		(0.40	)		(0.82	)
Depreciation and amortization		(0.02	)		(0.04	)
Deferral of new regulatory assets		(0.10	)		(0.13	)
General taxes		0.02			(0.01	)
Corporate-owned life insurance		(0.04	)		(0.09	)
Other expenses		0.04			0.01
Reduced common shares outstanding		-			0.03
Basic Earnings Per Share – 2008	$	0.86		$	1.77

Regulatory Matters - Ohio

Legislative Process

On May 1, 2008, Governor Strickland signed SB221, which became effective on July 31, 2008. The bill requires all utilities to file an updated rate plan, now called an ESP, with the PUCO. A utility is also permitted to simultaneously file an MRO in which it would have to demonstrate certain objective market criteria. On July 31, 2008, FirstEnergy filed both an ESP and an MRO on behalf of its Ohio Companies. The comprehensive ESP includes supply and pricing for retail generation service for up to a three-year period, in addition to seeking approval of outstanding issues currently pending before the PUCO in the Ohio Companies’ distribution rate case. The MRO filing outlines a CBP for providing retail generation supply if the ESP is not approved and implemented. The CBP would use a “slice-of-system” approach where suppliers bid on tranches (approximately 100 MW) of the Ohio Companies’ total customer load. A PUCO decision on the ESP is required, by SB221, within 150 days and on the MRO within 90 days. New rates under the ESP would be effective for retail customers on January 1, 2009.

On July 2, 2008, and July 23, 2008, the PUCO staff issued proposed rules addressing portions of SB221 for comment. Stakeholder comments on the first set of rules have been submitted for consideration by the PUCO, and comments and reply comments on the second set are due August 12, 2008 and August 22, 2008, respectively. Proposed rules addressing other portions of SB221, including the alternative energy portfolio standard, are expected to be issued in late August. Final rules are expected to be adopted in late September. The rules will then be subject to review by the Joint Committee on Agency Rule Review (a group consisting of five State Representatives and five State Senators).

RCP Fuel Remand

On June 3, 2008, FirstEnergy made a filing on behalf of the Ohio Companies to suspend the procedural schedule in its application to recover the companies’ 2006-2007 deferred fuel costs and associated carrying charges since its ESP filing contains a proposal addressing the recovery of these deferred fuel costs. On June 4, 2008, the PUCO Staff issued a report in accordance with its previously established procedural schedule and on June 11, 2008, the PUCO denied FirstEnergy’s request to suspend proceedings until the ESP case is completed and revised the procedural schedule. Testimony is now due August 29, 2008, and an evidentiary hearing is scheduled for September 29, 2008.

1

Regulatory Matters - Pennsylvania

Penn’s Interim Default Service Supply

In April and May 2008, Penn held RFPs to procure its power supply for default service for residential customers for the period June 2008 through May 2009 and a portion of the load for June 2009 through May 2010. The PPUC approved the resulting bids and on May 20, 2008, Penn filed compliance tariffs with the new default service generation rates for residential customers, which the PPUC then certified on May 21, 2008. Penn’s new default service rates were effective June 1, 2008. RFPs for the remainder of the June 2009 through May 2010 residential customers’ load are scheduled for October 2008 and January 2009.

Met-Ed and Penelec Transmission Service Charge Filing

On May 22, 2008, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC riders for the period June 1, 2008, through May 31, 2009. The approved TSCs include a component for under-recovery of actual transmission costs incurred during prior periods and future transmission cost projections for June 2008 through May 2009. Met-Ed’s TSC includes a transition approach that will recover past under-recovered costs plus carrying charges through the new TSC, with deferral of a portion of the projected costs plus carrying charges for recovery through future TSCs by December 31, 2010. Various intervenors filed complaints against Met-Ed’s and Penelec’s TSC filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing the company to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation, and a litigation schedule was adopted with hearings for both companies scheduled to begin in January 2009.

Generation

Fremont Plant

In January 2008, FGCO acquired a partially complete 707-MW natural gas fired generating plant in Fremont, Ohio from Calpine Corporation for $253.6 million. FGCO completed an engineering study in June 2008, indicating an estimated additional $208 million of capital expenditures will be required to complete the project. Approximately $41 million of the incremental capital is expected to be invested in 2008 with planned commercial operation of the plant expected to begin in December 2009.

Refueling Outage and Power Uprates

On May 22, 2008, the 868-MW Beaver Valley Unit 2 returned to service following its regularly scheduled refueling outage that began on April 14, 2008. Major work activities completed during the outage included replacing approximately one-third of the fuel assemblies in the reactor and the high pressure turbine rotor. During the refueling outage, the final phase of an extended power uprate project was completed. This is the unit’s second uprate in the past 19 months.

On June 30, 2008, the NRC approved a 12 MW uprate at the 893-MW Davis-Besse Nuclear Power Station. These uprates were achieved in support of FirstEnergy’s strategy to maximize the full potential of its existing generation assets.

Financial Matters

New Long-Term Fuel Supply Arrangements

On July 16, 2008, FirstEnergy Ventures Corp., a subsidiary of FirstEnergy, entered into a joint venture with the Boich Companies, a Columbus, Ohio-based coal company, to acquire a majority stake in the Bull Mountain Mine Operations near Roundup, Montana. This transaction is part of FirstEnergy’s strategy to secure high-quality fuel supplies at attractive prices to maximize the capacity of its existing fossil generating plants. FirstEnergy will make a $125 million equity investment in the joint venture. Under an acquisition and development agreement, the joint venture will acquire 80 percent of the Bull Mountain mining operations and 100 percent of the transportation operations, with FirstEnergy owning a 45 percent economic interest and an affiliate of the Boich Companies owning a 55 percent economic interest in the joint venture, with both parties having a 50 percent voting interest in the joint venture. After January 2010, the joint venture will have 18 months to exercise an option to acquire the remaining 20 percent stake in the mining operations. In a related transaction, FirstEnergy has entered into a 15-year agreement to purchase all production up to 10 million tons of bituminous western coal annually from the mine. FirstEnergy also reached tentative agreements with the rail carriers associated with transporting coal from the mine to its generating stations, and it expects to begin taking delivery of the coal in late 2009 or early 2010. The joint venture has the right to resell FirstEnergy’s Bull Mountain coal tonnage not used at FirstEnergy’s facilities and has call rights on such coal above certain levels.

2

Acquisition of Additional Equity Interests in Beaver Valley Unit 2 and Perry

On May 30, 2008, NGC purchased 56.8 MW of lessor equity interests in the OE 1987 sale and leaseback of the Perry Plant. On June 2, 2008, NGC purchased approximately 43.5 MW of lessor equity interests in the OE 1987 sale and leaseback of Beaver Valley Unit 2. Between June 2, 2008 and June 9, 2008, NGC purchased an additional 158.5 MW of additional lessor equity interests in the TE and CEI 1987 sale and leaseback of Beaver Valley Unit 2, which purchases were undertaken in connection with the previously disclosed exercise of the periodic purchase option provided in the TE and CEI sale and leaseback arrangements. The Ohio Companies continue to lease these MW under the respective sale and leaseback arrangements and the related lease debt remains outstanding.

Refunding of Auction Rate Bonds

In June 2008, FGCO and NGC refunded all of the $455.7 million of PCRBs previously issued on their behalf as auction rate securities and recently repurchased in response to disruptions in the auction rate securities market. The new PCRBs were issued in variable-rate modes supported by bank LOCs. FirstEnergy no longer holds auction rate securities.

New Credit Facility

On May 30, 2008, FirstEnergy and FES entered into a new $300 million, 364-day revolving credit facility. The pricing, terms and conditions are substantially similar to those contained in the current FirstEnergy $2.75 billion revolving credit agreement.

FIRSTENERGY’S BUSINESS

FirstEnergy is a diversified energy 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 and default service requirements in Pennsylvania and New Jersey. This business segment derives its revenues principally from the delivery of electricity within FirstEnergy’s service areas at regulated rates, cost recovery of regulatory assets and the sale of electric generation service to retail customers who have not selected an alternative supplier (default service) in its Pennsylvania and New Jersey franchise areas. The segment’s net income reflects the commodity costs of securing electricity from FirstEnergy’s competitive energy services segment under partial requirements purchased power agreements with FES and from non-affiliated power suppliers, including, in each case, associated transmission costs.

·   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 and default service 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 or leases and operates 19 generating facilities with a net demonstrated capacity of approximately 13,664 MW and also purchases electricity to meet sales obligations. The segment's net income is primarily derived from affiliated company power sales and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission 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 default service requirements of the 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, including net transmission and ancillary costs charged by MISO to deliver energy to retail customers.

3

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 13 to the consolidated financial statements. Net income by major business segment was as follows:

	Three Months Ended June 30									Six Months Ended June 30
							Increase									Increase
	2008			2007			(Decrease)			2008			2007			(Decrease)
	(In millions, except per share data)
Net Income
By Business Segment:
Energy delivery services	$	193		$	207		$	(14	)	$	372		$	425		$	(53	)
Competitive energy services		66			142			(76	)		153			240			(87	)
Ohio transitional generation services		20			30			(10	)		43			53			(10	)
Other and reconciling adjustments*		(16	)		(41	)		25			(29	)		(90	)		61
Total	$	263		$	338		$	(75	)	$	539		$	628		$	(89	)
Basic Earnings Per Share	$	0.86		$	1.11		$	(0.25	)	$	1.77		$	2.03		$	(0.26	)
Diluted Earnings Per Share	$	0.85		$	1.10		$	(0.25	)	$	1.75		$	2.01		$	(0.26	)

* Consists primarily of interest expense related to holding company debt, corporate support services revenues and expenses, telecommunications services and elimination of intersegment transactions.

Summary of Results of Operations – Second Quarter 2008 Compared with Second Quarter 2007

Financial results for FirstEnergy's major business segments in the second quarter of 2008 and 2007 were as follows:

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
Second Quarter 2008 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	2,030		$	324		$	670		$	-		$	3,024
Other		152			51			13			5			221
Internal		-			704			-			(704	)		-
Total Revenues		2,182			1,079			683			(699	)		3,245
Expenses:
Fuel and purchased power		998			537			555			(704	)		1,386
Other operating expenses		413			312			81			(25	)		781
Provision for depreciation		104			59			-			5			168
Amortization of regulatory assets		235			-			11			-			246
Deferral of new regulatory assets		(98	)		-			-			-			(98	)
General taxes		149			24			2			5			180
Total Expenses		1,801			932			649			(719	)		2,663
Operating Income		381			147			34			20			582
Other Income (Expense):
Investment income		40			(8	)		(1	)		(15	)		16
Interest expense		(100	)		(38	)		-			(50	)		(188	)
Capitalized interest		1			10			-			2			13
Total Other Expense		(59	)		(36	)		(1	)		(63	)		(159	)
Income Before Income Taxes		322			111			33			(43	)		423
Income taxes		129			45			13			(27	)		160
Net Income	$	193		$	66		$	20		$	(16	)	$	263

4

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
Second Quarter 2007 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	1,933		$	359		$	612		$	-		$	2,904
Other		162			39			13			(9	)		205
Internal		-			691			-			(691	)		-
Total Revenues		2,095			1,089			625			(700	)		3,109
Expenses:
Fuel and purchased power		879			460			537			(691	)		1,185
Other operating expenses		410			277			87			(24	)		750
Provision for depreciation		100			51			-			8			159
Amortization of regulatory assets		242			-			6			(2	)		246
Deferral of new regulatory assets		(93	)		-			(55	)		-			(148	)
General taxes		155			26			1			7			189
Total Expenses		1,693			814			576			(702	)		2,381
Operating Income		402			275			49			2			728
Other Income (Expense):
Investment income		62			5			-			(37	)		30
Interest expense		(118	)		(47	)		-			(40	)		(205	)
Capitalized interest		2			5			-			-			7
Total Other Expense		(54	)		(37	)		-			(77	)		(168	)
Income Before Income Taxes		348			238			49			(75	)		560
Income taxes		141			96			19			(34	)		222
Net Income	$	207		$	142		$	30		$	(41	)	$	338
Changes Between Second Quarter 2008 and
Second Quarter 2007 Financial Results
Increase (Decrease)
Revenues:
External
Electric	$	97		$	(35	)	$	58		$	-		$	120
Other		(10	)		12			-			14			16
Internal		-			13			-			(13	)		-
Total Revenues		87			(10	)		58			1			136
Expenses:
Fuel and purchased power		119			77			18			(13	)		201
Other operating expenses		3			35			(6	)		(1	)		31
Provision for depreciation		4			8			-			(3	)		9
Amortization of regulatory assets		(7	)		-			5			2			-
Deferral of new regulatory assets		(5	)		-			55			-			50
General taxes		(6	)		(2	)		1			(2	)		(9	)
Total Expenses		108			118			73			(17	)		282
Operating Income		(21	)		(128	)		(15	)		18			(146	)
Other Income (Expense):
Investment income		(22	)		(13	)		(1	)		22			(14	)
Interest expense		18			9			-			(10	)		17
Capitalized interest		(1	)		5			-			2			6
Total Other Expense		(5	)		1			(1	)		14			9
Income Before Income Taxes		(26	)		(127	)		(16	)		32			(137	)
Income taxes		(12	)		(51	)		(6	)		7			(62	)
Net Income	$	(14	)	$	(76	)	$	(10	)	$	25		$	(75	)

5

Energy Delivery Services – Second Quarter 2008 Compared with Second Quarter 2007

Net income decreased $14 million to $193 million in the second quarter of 2008 compared to $207 million in the second quarter of 2007, primarily due to higher fuel and purchased power expenses partially offset by increased revenues.

Revenues –

The increase in total revenues resulted from the following sources:

	Three Months
	Ended June 30				Increase
Revenues by Type of Service	2008		2007		(Decrease)
	(In millions)
Distribution services	$	919	$	948	$	(29	)
Generation sales:
Retail		772		756		16
Wholesale		252		148		104
Total generation sales		1,024		904		120
Transmission		196		194		2
Other		43		49		(6	)
Total Revenues	$	2,182	$	2,095	$	87

The decrease in distribution deliveries by customer class is summarized in the following table:

Electric Distribution KWH Deliveries
Residential	(5.0	)%
Commercial	(2.1	)%
Industrial	(0.3	)%
Total Distribution KWH Deliveries	(2.4	)%

The decrease in electric distribution deliveries to residential and commercial customers was primarily due to reduced weather-related usage during the second quarter of 2008 compared to the same period of 2007, as cooling and heating degree days decreased 11% and 7%, respectively. In the industrial sector, a decrease in deliveries to automotive manufacturers was nearly offset by an increase in usage by steel and refining customers. The lower distribution revenues primarily resulted from the reduction in sales volume, as unit prices were virtually unchanged from the previous year.

The following table summarizes the price and volume factors contributing to the $120 million increase in generation revenues in the second quarter of 2008 compared to the second quarter of 2007:

Sources of Change in Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of 4.2% decrease in sales volumes	$	(32	)
Change in prices		48
		16
Wholesale:
Effect of 3.0% increase in sales volumes		5
Change in prices		99
		104
Net Increase in Generation Revenues	$	120

The decrease in retail generation sales volumes was primarily due to an increase in customer shopping in Penn’s and JCP&L’s service territories and the weather-related impacts described above. The increase in retail generation prices during the second quarter of 2008 reflected increased generation rates for JCP&L resulting from the New Jersey BGS auction process and an increase in NUGC rates authorized by the NJBPU. Wholesale generation sales increased principally as a result of Met-Ed and JCP&L selling additional available power into the PJM market. The increase in prices reflected higher spot market prices for PJM market participants.

Transmission revenues increased $2 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the annual update to their TSC riders, which became effective June 1, 2008. Met-Ed and Penelec defer the difference between revenues from their transmission rider and transmission costs incurred with no material effect on current period earnings (see Outlook – State Regulatory Matters – Pennsylvania).

6

Expenses –

The increases in revenues discussed above were offset by a $108 million increase in expenses due to the following:

· Purchased power costs were $122million higher in the second quarter of 2008 due to higher unit costs and a decrease in the amount of NUG costs deferred. The increased unit costs reflected the effect of higher JCP&L costs resulting from the BGS auction process. However, 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. The following table summarizes the sources of changes in purchased power costs:

Source of Change in Purchased Power	Increase (Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to increased unit costs	$	141
Change due to decreased volumes		(22	)
		119
Purchases from FES:
Change due to decreased unit costs		(2	)
Change due to decreased volumes		(7	)
		(9	)
Decrease in NUG costs deferred		12
Net Increase in Purchased Power Costs	$	122

· Other operating expenses increased $3 million due primarily to the net effects of the following:

-   an increase in labor expenses of $7 million primarily due to an increase in the number of employees in the second quarter of 2008 compared to 2007 as a result of the segment’s workforce initiatives;

-   reduced life insurance investment values of $5 million during the second quarter of 2008;

-   a decrease of $4million in MISO and PJM transmission expenses, resulting primarily from lower congestion costs; and,

-   reduced tree trimming expenses of $2 million.

· Amortization of regulatory assets decreased by $7 million compared to the second quarter of 2007, due primarily to the full recovery of certain regulatory costs for JCP&L.

· The deferral of new regulatory assets during the second quarter of 2008 was $5 million higher primarily due to an increase to the societal benefits cost deferral.

                ·   Depreciation expense increased $4million due to property additions since the second quarter of 2007.

                ·   General taxes decreased $6 million due to lower property taxes.

Other Expense –

Other expense increased $5million in the second quarter of 2008 primarily due to lower investment income ($22million) resulting from the repayment of notes receivable from affiliates since the second quarter of 2007, partially offset by lower interest expense (net of capitalized interest) of $17million due to redemptions of pollution control notes and term notes and reduced money pool borrowings.

Competitive Energy Services – Second Quarter 2008 Compared with Second Quarter 2007

Net income for this segment was $66million in the second quarter of 2008 compared to $142million in the same period in 2007. The $76 million reduction in net income reflects a decrease in gross generation margin and higher operating costs partially offset by lower interest expense.

7

Revenues –

Total revenues decreased $10million in the second quarter of 2008 due to lower non-affiliated generation sales partially offset by higher unit prices on affiliated generation sales to the Ohio Companies and higher transmission revenues.

The net decrease in total revenues resulted from the following sources:

	Three Months
	Ended June 30				Increase
Revenues By Type of Service	2008		2007		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	154	$	185	$	(31	)
Wholesale		170		174		(4	)
Total Non-Affiliated Generation Sales		324		359		(35	)
Affiliated Generation Sales		704		691		13
Transmission		33		22		11
Other		18		17		1
Total Revenues	$	1,079	$	1,089	$	(10	)

The lower retail revenues resulted from decreased sales in the PJM market due primarily to lower contract renewals for commercial and industrial customers. Lower non-affiliated wholesale revenues resulted from the effect of reduced generation available for sale to that market as total generation output declined by 8% from the second quarter of 2007. An increase in prices for non-affiliated wholesale sales, reflecting higher spot market prices, partially offset the decline in volume.

The increased affiliated company generation revenues were due to higher unit prices for sales to the Ohio Companies, partially offset by reduced volumes and lower unit prices for the Pennsylvania Companies. The higher unit prices reflected increases in the Ohio Companies’ retail generation rates. The reduction in PSA sales volume to the Ohio and Pennsylvania Companies was due to the milder weather discussed above and reduced default service requirements in Penn’s service territory as a result of its RFP process (see Outlook – State Regulatory Matters – Pennsylvania).

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

Source of Change in Non-Affiliated Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of 16.4% decrease in sales volumes	$	(30	)
Change in prices		(1	)
		(31	)
Wholesale:
Effect of 15.3% decrease in sales volumes		(27	)
Change in prices		23
		(4	)
Net Decrease in Non-Affiliated Generation Revenues	$	(35	)

Source of Change in Affiliated Generation Revenues	Increase (Decrease)
	(In millions)
Ohio Companies:
Effect of 2.6% decrease in sales volumes	$	(14	)
Change in prices		37
		23
Pennsylvania Companies:
Effect of 4.3% decrease in sales volumes		(7	)
Change in prices		(3	)
		(10	)
Net Increase in Affiliated Generation Revenues	$	13

Transmission revenues increased $11 million due primarily to an increase in transmission prices in the PJM market.

8

Expenses -

Total expenses increased $118 million in the second quarter of 2008 due to the following factors:

·   Fossil fuel costs increased $14 million due primarily to higher unit prices ($58 million) partially offset by lower generation volumes ($44 million). The increased unit prices primarily reflect higher coal transportation costs (including surcharges for increased diesel fuel prices) in the second quarter of 2008. Nuclear fuel expense increased $4 million due to increased generation.

           · Purchased power costs increased $59 million due primarily to higher market rates, partially offset by reduced volume requirements.

·   Other operating expenses were higher by $35 million due, in part, to an increase in scheduled outage activity for fossil units ($24 million), a decrease in gains from the sale of excess emission allowances ($7 million), the assignment of CEI’s and TE’s leasehold interests in the Bruce Mansfield Plant to FGCO in the fourth quarter of 2007 ($12 million) and reduced life insurance investment values during the second quarter of 2008 ($4 million).

           · Higher depreciation expense of $8 million was due to property additions since the second quarter of 2007.

Partially offsetting the higher costs were:

           · Nuclear operating costs decreased $8 million, as expenses associated with this year’s Beaver Valley Unit 2 refueling outage were comparatively less than the Perry outage in the second quarter of 2007. In 2007, Perry’s outage extended 11 days beyond the original plan.

·   Transmission expense declined $4 million due to reduced PJM congestion charges of $17 million partially offset by increased MISO transmission expense of $13 million.

           · Lower general taxes of $2 million resulted from lower property taxes.

Other Expense –

Total other expense in the second quarter of 2008 was $1million lower than the second quarter of 2007, primarily due to a decrease in interest expense (net of capitalized interest) of $14 million from the repayment of notes payable to affiliates since the second quarter of 2007, partially offset by a $13 million decrease in earnings from nuclear decommissioning trust investments, which included a $12 million increase in securities impairments.

Ohio Transitional Generation Services – Second Quarter 2008 Compared with Second Quarter 2007

Net income for this segment decreased to $20million in the second quarter of 2008 from $30 million in the same period of 2007. Higher purchased power expenses and lower cost deferrals were only partially offset by higher generation revenues.

Revenues –

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

	Three Months
	Ended June 30
Revenues by Type of Service	2008		2007		Increase
	(In millions)
Generation sales:
Retail	$	587	$	544	$	43
Wholesale		3		2		1
Total generation sales		590		546		44
Transmission		93		79		14
Total Revenues	$	683	$	625	$	58

9

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

Source of Change in Retail Generation Revenues	Increase (Decrease)
	(In millions)
Effect of 2.5% decrease in sales volumes	$	(14	)
Change in prices		57
Net Increase in Retail Generation Revenues	$	43

The decrease in generation sales was primarily due to lower weather-related usage in the second quarter of 2008 compared to the same period of 2007 partially offset by reduced customer shopping. Cooling degree days in OE’s, CEI’s and TE’s service territories decreased by 26%, 16% and 33%, respectively. Average prices increased primarily due to an increase in the Ohio Companies’ fuel cost recovery rider that became effective in January 2008. The percentage of generation services provided by alternative suppliers to total sales delivered by the Ohio Companies in their service areas decreased to 14.7% in the second quarter of 2008 from 15.2% in the same period in 2007.

Increased transmission revenue resulted from a PUCO-approved transmission tariff increase that became effective July 1, 2007.

Expenses -

Purchased power costs were $18million higher due primarily to higher unit costs 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 (Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to decreased unit costs	$	(1	)
Change due to decreased volumes		(3	)
		(4	)
Purchases from FES:
Change due to increased unit costs		36
Change due to decreased volumes		(14	)
		22
Net Increase in Purchased Power Costs	$	18

The decrease in purchase volumes from FES was due to the lower retail generation sales requirements described above. The higher unit costs reflect the increases in the Ohio Companies’ retail generation rates, as provided for under the PSA with FES.

Other operating expenses decreased $6 million due primarily to lower MISO transmission-related expenses. The difference between transmission revenues accrued and transmission expenses incurred is deferred, resulting in no material impact to current period earnings.

The deferral of new regulatory assets decreased by $55 million in the second quarter of 2008 as compared to the same period in 2007. MISO transmission deferrals and RCP fuel deferrals each decreased $28 million as more transmission and generation costs were recovered from customers through PUCO-approved riders.

Other – Second Quarter 2008 Compared with Second Quarter 2007

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 $25 million increase in FirstEnergy’s net income in the second quarter of 2008 compared to the same period in 2007. The increase primarily resulted from a $15 million litigation settlement relating to formerly-owned international assets, $6 million of interest income related to the settlement and a $9 million reduction of interest expense associated with the revolving credit facility.

.

10

Summary of Results of Operations – First Six Months of 2008 Compared with the First Six Months of 2007

Financial results for FirstEnergy's major business segments in the first six months of 2008 and 2007 were as follows:

							Ohio
	Energy			Competitive			Transitional				Other and
	Delivery			Energy			Generation				Reconciling			FirstEnergy
First Six Months 2008 Financial Results	Services			Services			Services				Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	4,080		$	613		$	1,361			$	-		$	6,054
Other		314			91			29		��		34			468
Internal		-			1,480			-				(1,480	)		-
Total Revenues		4,394			2,184			1,390				(1,446	)		6,522
Expenses:
Fuel and purchased power		1,981			1,070			1,143				(1,480	)		2,714
Other operating expenses		858			621			158				(56	)		1,581
Provision for depreciation		210			112			-				10			332
Amortization of regulatory assets		484			-			20				-			504
Deferral of new regulatory assets		(198	)		-			(5	)			-			(203	)
General taxes		322			56			3				14			395
Total Expenses		3,657			1,859			1,319				(1,512	)		5,323
Operating Income		737			325			71				66			1,199
Other Income (Expense):
Investment income		85			(14	)		-				(38	)		33
Interest expense		(203	)		(72	)		-				(92	)		(367	)
Capitalized interest		1			17			-				3			21
Total Other Expense		(117	)		(69	)		-				(127	)		(313	)
Income Before Income Taxes		620			256			71				(61	)		886
Income taxes		248			103			28				(32	)		347
Net Income	$	372		$	153		$	43			$	(29	)	$	539

11

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
First Six Months 2007 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	3,808		$	635		$	1,226		$	-		$	5,669
Other		327			84			19			(17	)		413
Internal		-			1,404			-			(1,404	)		-
Total Revenues		4,135			2,123			1,245			(1,421	)		6,082
Expenses:
Fuel and purchased power		1,722			907			1,081			(1,404	)		2,306
Other operating expenses		819			575			138			(33	)		1,499
Provision for depreciation		199			102			-			14			315
Amortization of regulatory assets		487			-			11			(1	)		497
Deferral of new regulatory assets		(217	)		-			(75	)		-			(292	)
General taxes		320			55			2			15			392
Total Expenses		3,330			1,639			1,157			(1,409	)		4,717
Operating Income		805			484			88			(12	)		1,365
Other Income (Expense):
Investment income		132			8			1			(78	)		63
Interest expense		(227	)		(100	)		(1	)		(62	)		(390	)
Capitalized interest		4			8			-			-			12
Total Other Expense		(91	)		(84	)		-			(140	)		(315	)
Income Before Income Taxes		714			400			88			(152	)		1,050
Income taxes		289			160			35			(62	)		422
Net Income	$	425		$	240		$	53		$	(90	)	$	628
Changes Between First Six Months 2008
and First Six Months 2007
Financial Results Increase (Decrease)
Revenues:
External
Electric	$	272		$	(22	)	$	135		$	-		$	385
Other		(13	)		7			10			51			55
Internal		-			76			-			(76	)		-
Total Revenues		259			61			145			(25	)		440
Expenses:
Fuel and purchased power		259			163			62			(76	)		408
Other operating expenses		39			46			20			(23	)		82
Provision for depreciation		11			10			-			(4	)		17
Amortization of regulatory assets		(3	)		-			9			1			7
Deferral of new regulatory assets		19			-			70			-			89
General taxes		2			1			1			(1	)		3
Total Expenses		327			220			162			(103	)		606
Operating Income		(68	)		(159	)		(17	)		78			(166	)
Other Income (Expense):
Investment income		(47	)		(22	)		(1	)		40			(30	)
Interest expense		24			28			1			(30	)		23
Capitalized interest		(3	)		9			-			3			9
Total Other Expense		(26	)		15			-			13			2
Income Before Income Taxes		(94	)		(144	)		(17	)		91			(164	)
Income taxes		(41	)		(57	)		(7	)		30			(75	)
Net Income	$	(53	)	$	(87	)	$	(10	)	$	61		$	(89	)

12

Energy Delivery Services – First Six Months of 2008 Compared to First Six Months of 2007

Net income decreased $53 million to $372 million in the first six months of 2008 compared to $425 million in the first six months of 2007, primarily due to increased operating expenses and lower investment income partially offset by higher revenues.

Revenues –

The increase in total revenues resulted from the following sources:

	Six Months
	Ended June 30				Increase
Revenues by Type of Service	2008		2007		(Decrease)
	(In millions)
Distribution services	$	1,874	$	1,892	$	(18	)
Generation sales:
Retail		1,562		1,476		86
Wholesale		471		281		190
Total generation sales		2,033		1,757		276
Transmission		393		376		17
Other		94		110		(16	)
Total Revenues	$	4,394	$	4,135	$	259

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

Electric Distribution KWH Deliveries
Residential	(1.0	)%
Commercial	(0.1	)%
Industrial	(0.7	)%
Total Distribution KWH Deliveries	(0.6	)%

The decrease in electric distribution deliveries to customers was primarily due to lower weather-related usage during the first six months of 2008 compared to the same period of 2007, as cooling degree days decreased by 11% and heating degree days decreased by 2%. The lower revenues reflected the decreased distribution deliveries and the residual effects of the 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 $276 million increase in generation revenues in the first six months of 2008 compared to the same period of 2007:

	Increase
Sources of Change in Generation Revenues	(Decrease)
	(In millions)
Retail:
Effect of 2.4% decrease in sales volumes	$	(36	)
Change in prices		122
		86
Wholesale:
Effect of 5.9% increase in sales volumes		16
Change in prices		174
		190
Net Increase in Generation Revenues	$	276

The decrease in retail generation sales volumes reflected an increase in customer shopping in Penn’s and JCP&L’s service territories and the weather-related impacts described above. The increase in retail generation prices during the first six months of 2008 was due to higher generation rates for JCP&L resulting from the New Jersey BGS auction process and an increase in NUGC rates authorized by the NJBPU. Wholesale generation sales increased principally as a result of Met-Ed and Penelec selling additional available power into the PJM market. The increase in wholesale prices reflected higher spot market prices for PJM market participants.

Transmission revenues increased $17 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the January 2007 PPUC authorization of transmission cost recovery and the annual update to their TSC riders, which became effective June 1, 2008. Met-Ed and Penelec defer the difference between revenues from their transmission rider and transmission costs incurred with no material effect on current period earnings (see Outlook – State Regulatory Matters – Pennsylvania).

13

Expenses –

The net increases in revenues discussed above were more than offset by a $327 million increase in expenses due to the following:

· Purchased power costs were $260million higher in the first six months of 2008 due to higher unit costs and a decrease in the amount of NUG costs deferred. The increased unit costs primarily reflected the effect of higher JCP&L costs resulting from the BGS auction process. The following table summarizes the sources of changes in purchased power costs:

Source of Change in Purchased Power	Increase (Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to increased unit costs	$	225
Change due to decreased volumes		(40	)
		185
Purchases from FES:
Change due to decreased unit costs		(7	)
Change due to increased volumes		10
		3
Decrease in NUG costs deferred		72
Net Increase in Purchased Power Costs	$	260

· Other operating expenses increased $39million due to the net effects of:

-   an increase of $11million in MISO and PJM transmission expenses, resulting primarily from higher congestion costs (see transmission revenues discussion above);

-   reduced life insurance investment values of $12 million during the first six months of 2008; and

-   an increase in labor expenses of $16million primarily due to an increase in the number of employees in the first six months of 2008 compared to 2007 as a result of the segment’s workforce initiatives.

· A decrease of $3 million in amortization of regulatory assets compared to 2007 due primarily to the complete recovery of certain regulatory costs for JCP&L.

· The deferral of new regulatory assets during the first six months of 2008 was $19 million lower primarily due to the absence of the one-time deferral in 2007 of decommissioning costs related to the Saxton nuclear research facility.

                 ·   Depreciation expense increased $11 million due to property additions since the second quarter of 2007.

                 ·   General taxes increased $2 million due to higher gross receipts and payroll taxes.

Other Expense –

Other expense increased $26 million in the first six months of 2008 compared to 2007 primarily due to lower investment income of $47 million, resulting primarily from the repayment of notes receivable from affiliates since the second quarter of 2007, partially offset by lower interest expense (net of capitalized interest) of $21 million.

Competitive Energy Services – First Six Months of 2008 Compared to First Six Months of 2007

Net income for this segment was $153million in the first six months of 2008 compared to $240million in the same period in 2007. The $87 million reduction in net income reflects a decrease in gross generation margin and higher other operating costs which were partially offset by lower interest expense.

14

Revenues –

Total revenues increased $61million in the first six months of 2008 compared to the same period in 2007. This increase primarily resulted from higher unit prices on affiliated generation sales to the Ohio Companies and increased non-affiliated wholesale sales partially offset by lower retail sales.

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

	Six Months
	Ended June 30				Increase
Revenues by Type of Service	2008		2007		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	315	$	359	$	(44	)
Wholesale		298		276		22
Total Non-Affiliated Generation Sales		613		635		(22	)
Affiliated Generation Sales		1,480		1,404		76
Transmission		66		45		21
Other		25		39		(14	)
Total Revenues	$	2,184	$	2,123	$	61

The lower retail revenues resulted from decreased sales in the PJM market, partially offset by increased sales in the MISO market. The decrease in PJM retail sales is primarily the result of lower contract renewals for commercial and industrial customers. The increase in MISO retail sales is primarily the result of capturing more shopping customers in Penn’s service territory, partially offset by lower customer usage. Higher non-affiliated wholesale revenues resulted from higher spot market prices in PJM, partially offset by decreased sales volumes in MISO.

The increased affiliated company generation revenues were due to higher unit prices for the Ohio Companies and increased sales volumes to the Pennsylvania Companies, partially offset by lower unit prices for the Pennsylvania Companies. The higher unit prices reflected increases in the Ohio Companies’ retail generation rates. The higher sales to the Pennsylvania Companies were due to increased Met-Ed and Penelec generation sales requirements, partially offset by lower sales to Penn due to decreased default service requirements in the first six months of 2008 compared to the first six months of 2007.

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 Revenues	(Decrease)
	(In millions)
Retail:
Effect of 12.8% decrease in sales volumes	$	(46	)
Change in prices		2
		(44	)
Wholesale:
Effect of 7.6% decrease in sales volumes		(21	)
Change in prices		43
		22
Net Decrease in Non-Affiliated Generation Revenues	$	(22	)

	Increase
Source of Change in Affiliated Generation Revenues	(Decrease)
	(In millions)
Ohio Companies:
Effect of 0.6% decrease in sales volumes	$	(7	)
Change in prices		80
		73
Pennsylvania Companies:
Effect of 2.8% increase in sales volumes		10
Change in prices		(7	)
		3
Net Increase in Affiliated Generation Revenues	$	76

Transmission revenues increased $21 million due to higher transmission rates in MISO and PJM. Other revenue decreased $14 million primarily due to lower interest income from short-term investments.

15

Expenses -

Total expenses increased $220 million in the first six months of 2008 due to the following factors:

·   Fossil fuel costs increased $82 million due to higher unit prices ($90 million) partially offset by lower generation volumes ($8 million). The increased unit prices primarily reflect higher coal transportation costs (including surcharges for increased diesel fuel prices) and increased emission allowance costs in the first six months of 2008. Nuclear fuel expense was $3 million higher in the first half of 2008.

       · Purchased power costs increased $78 million due primarily to higher spot market prices, partially offset by reduced volume requirements.

       · Nuclear operating costs increased $15 million in the first six months of 2008 due to an additional refueling outage during the 2008 period.

·   Other expense increased $33 million due primarily to the assignment of CEI’s and TE’s leasehold interests in the Bruce Mansfield Plant to FGCO in the fourth quarter of 2007 ($20 million) and reduced life insurance investment values during the first six months of 2008 ($9 million).

            · Higher depreciation expenses of $10 million were due to property additions since the second quarter of 2007.

·   Fossil operating costs were $8 million higher due to planned maintenance outages in 2008, employee benefits and reduced gains from emission allowance sales.

·   Higher general taxes of $1 million resulted from higher payroll taxes.

Partially offsetting the higher costs above was a decrease in transmission expense of $11 million due to reduced PJM congestion charges and a change in MISO revenue sufficiency guarantee settlements.

Other Expense –

Total other expense in the first six months of 2008 was $15million lower than the first six months of 2007, primarily due to a decline in interest expense (net of capitalized interest) of $37 million from the repayment of notes payable to affiliates since the second quarter of 2007, partially offset by a $22 million decrease in earnings from nuclear decommissioning trust investments due primarily to securities impairments.

Ohio Transitional Generation Services – First Six Months of 2008 Compared to First Six Months of 2007

Net income for this segment decreased to $43million in the first six months of 2008 from $53 million in the same period of 2007. Higher operating expenses, primarily for purchased power, and a decrease in the deferral of new regulatory assets were partially offset by higher generation revenues.

Revenues –

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

	Six Months
	Ended June 30
Revenues by Type of Service	2008		2007		Increase
	(In millions)
Generation sales:
Retail	$	1,193	$	1,090	$	103
Wholesale		5		4		1
Total generation sales		1,198		1,094		104
Transmission		186		150		36
Other		6		1		5
Total Revenues	$	1,390	$	1,245	$	145

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

Source of Change in Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of 0.5% decrease in sales volumes	$	(5	)
Change in prices		108
Net Increase in Retail Generation Revenues	$	103

The decrease in generation sales volume in the first six months of 2008 was primarily due to milder weather in the second quarter, which was partially offset by the higher weather-related usage in the first quarter and reduced customer shopping. Cooling degree days in OE’s, CEI’s and TE’s service territories for the first six months of 2008 decreased by 26%, 17% and 34%, respectively. Average prices increased primarily due to an increase in the Ohio Companies’ fuel cost recovery riders that became effective in January 2008. The percentage of generation services provided by alternative suppliers to total sales delivered by the Ohio Companies in their service areas decreased to 14.3% in the first half of 2008 from 14.8% in the same period in 2007.

Increased transmission revenue resulted from a PUCO-approved transmission tariff increase that became effective July 1, 2007. The difference between transmission revenues accrued and transmission expenses incurred is deferred, resulting in no material impact to current period earnings.

Expenses -

Purchased power costs were $62million higher due primarily to higher unit costs for power purchased from FES. The factors contributing to the higher costs are summarized in the following table:

	Increase
Source of Change in Purchased Power	(Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to decreased unit costs	$	(3	)
Change due to decreased volumes		(8	)
		(11	)
Purchases from FES:
Change due to increased unit costs		80
Change due to decreased volumes		(7	)
		73
Net Increase in Purchased Power Costs	$	62

The higher unit costs reflect the increases in the Ohio Companies’ retail generation rates, as provided for under the PSA with FES. The decrease in purchase volumes from FES was due to the lower retail generation sales requirements described above.

Other operating expenses increased $20 million due to lower associated company cost reimbursements related to the Ohio Companies’ generation leasehold interests partially offset by lower MISO transmission-related expenses.

The deferral of new regulatory assets decreased by $70 million in the first six months of 2008 as compared to the same period in 2007. MISO transmission deferrals decreased $34 million and RCP fuel deferrals decreased $36 million as more transmission and generation costs were recovered from customers through PUCO-approved riders.

Other – First Six Months of 2008 Compared to First Six Months of 2007

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 $61 million increase in FirstEnergy’s net income in the first six months of 2008 compared to the same period in 2007. The increase resulted primarily from the sale of telecommunication assets ($19 million, net of taxes), a $15 million litigation settlement relating to formerly-owned international assets and associated interest of $6 million, and a $20 million reduction of interest expense associated with the revolving credit facility.

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CAPITAL RESOURCES AND LIQUIDITY

FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. In 2008 and in subsequent years, FirstEnergy expects to satisfy these requirements 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.

As of June 30, 2008, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was principally due to  short-term borrowings to fund capital expenditures for environmental compliance and the classification of certain variable interest rate PCRBs as currently payable long-term debt. The PCRBs currently permit individual debt holders to put the respective debt back to the issuer for purchase prior to maturity.

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 and certain of its subsidiaries also have access to $2.75 billion of short-term financing under a revolving credit facility which expires in 2012. Under the terms of the facility, FirstEnergy is permitted to have up to $1.5 billion in outstanding borrowings at any time, subject to the facility cap of $2.75 billion of aggregate outstanding borrowings by it and its subsidiaries that are also parties to such facility. In the first six months of 2008, FirstEnergy received $200 million of cash dividends from its subsidiaries and paid $335 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.

As of June 30, 2008, FirstEnergy had $70 million of cash and cash equivalents compared with $129 million as of December 31, 2007. 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 services and competitive energy services businesses (see Results of Operations above). Net cash provided from operating activities was $316 million and $170 million in the first six months of 2008 and 2007, respectively, as summarized in the following table:

	Six Months
	Ended June 30
Operating Cash Flows	2008			2007
	(In millions)
Net income	$	539		$	628
Non-cash charges		414			277
Pension trust contribution		-			(300	)
Working capital and other		(637	)		(435	)
	$	316		$	170

Net cash provided from operating activities increased by $146 million in the first six months of 2008 compared to the first six months of 2007 primarily due to the absence of a $300 million pension trust contribution in 2007 and a $137 million increase in non-cash charges, partially offset by a $202 million decrease from working capital and other changes and an $89 million decrease in net income (see Results of Operations above). The increase in non-cash charges is primarily due to lower deferrals of new regulatory assets and purchased power costs. The deferral of new regulatory assets decreased primarily as a result of the Ohio Companies’ transmission and fuel recovery riders that became effective in July 2007 and January 2008, respectively, and the absence of the deferral of decommissioning costs related to the Saxton nuclear research facility in the first six months of 2007. Deferred purchased power costs decreased as a result of lower deferred NUG costs. The changes in working capital and other primarily resulted from higher materials and supplies inventories and increased tax payments, partially offset by a $146 million change in the collection of receivables and a $124 million change in the settlement of accounts payable compared to the first six months of 2007.

Cash Flows From Financing Activities

In the first six months of 2008, cash provided from financing activities was $1.2 billion compared to $454 million in the first six months of 2007. The increase was primarily due to lower debt issuances and higher short-term borrowings in the first six months of 2008, and the absence of the redemption of common stock in the first six months of 2007. The following table summarizes security issuances and redemptions.

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	Six Months
	Ended June 30
Securities Issued or Redeemed	2008		2007
	(In millions)
New issues
Pollution control notes	$	529	$	-
Unsecured notes		20		800
	$	549	$	800
Redemptions
First mortgage bonds	$	1	$	275
Pollution control notes		529		-
Senior secured notes		15		43
Unsecured notes		175		153
Common stock		-		918
	$	720	$	1,389
Short-term borrowings, net	$	1,705	$	1,308

FirstEnergy had approximately $2.6 billion of short-term indebtedness as of June 30, 2008 compared to approximately $903 million as of December 31, 2007. Available bank borrowing capability as of June 30, 2008 included the following:

Borrowing Capability (In millions)
Short-term credit facilities(1)	$	3,170
Accounts receivable financing facilities		550
Utilized		(2,606	)
LOCs		(50	)
Net available capability	$	1,064
(1) Includes the $2.75 billion revolving credit facility described below, a $100 million revolving credit facility that expires in December 2009, a $300 million revolving credit facility that expires in May 2009 and a $20 million uncommitted line of credit.

As of June 30, 2008, the Ohio Companies and Penn had the aggregate capability to issue approximately $3.5 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 $579 million, $459 million and $124 million, respectively, as of June 30, 2008.  On June 19, 2008, FGCO established an FMB indenture. Based upon its net earnings and available bondable property additions, as of June 30, 2008, FGCO had the capability to issue $2.8 billion of additional FMB under the terms of this new indenture.

As of June 30, 2008, FirstEnergy had approximately $1.0 billion of remaining unused capacity under an existing shelf registration statement filed with the SEC in 2003 to support future securities issuances. The shelf registration expires in December 2008 and 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. FirstEnergy currently intends to replace this registration statement by filing an automatic shelf registration statement that will not be required to specify the amount of securities to be offered thereon. As of June 30, 2008, OE had approximately $400 million of remaining unused capacity under a shelf registration for unsecured debt securities filed with the SEC in 2006 that expires in April 2009.

FirstEnergy and certain of its subsidiaries are party to a $2.75 billion revolving credit facility (included in the borrowing capability table above). FirstEnergy has the capability to 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, 2012, unless the lenders agree, at the request of the borrowers, to an unlimited number of 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.

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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		$	-	(2)
OE		500			500
Penn		50			39	(3)
CEI		250	(4)		500
TE		250	(4)		500
JCP&L		425			428	(3)
Met-Ed		250			300	(3)
Penelec		250			300	(3)
FES		1,000			-	(2)
ATSI		-	(5)		50
(1)As of June 30, 2008. (2)No regulatory approvals, statutory or charter limitations applicable. (3)Excluding amounts which may be borrowed under the regulated companies’ money pool. (4)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.  (5)The borrowing sub-limit for ATSI may be increased up to $100 million by delivering notice to the administrative agent that either (i) ATSI has senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody’s or (ii) FirstEnergy has guaranteed ATSI’s obligations of such borrower under the facility.

The revolving credit facility, combined with the $300 million and $100 million facilities referenced in the footnote to the borrowing capability table above and an aggregate $550 million ($294 million unused as of June 30, 2008) of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are used 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 June 30, 2008, FirstEnergy’s and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:

Borrower
FirstEnergy	60.0	%
OE	40.3	%
Penn	19.5	%
CEI	56.5	%
TE	39.3	%
JCP&L	33.8	%
Met-Ed	45.3	%
Penelec	49.6	%
FES(1)	64.9	%
(1) FES expects to remain in compliance with its debt covenant limitation.

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.

On May 30, 2008, FirstEnergy and FES entered into a new $300 million, 364-day revolving credit facility. The pricing, terms and conditions are substantially similar to those contained in the current FirstEnergy $2.75 billion revolving credit agreement.

20

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 six months of 2008 was 3.24% for the regulated companies’ money pool and 3.21% for the unregulated companies’ money pool.

FirstEnergy’s access to capital markets and costs of financing are influenced by the ratings of its securities. The following table displays FirstEnergy’s, FES’ and the Companies’ securities ratings as of June 30, 2008. On August 1, 2008, S&P changed its outlook for FirstEnergy and its subsidiaries from negative to stable. Moody’s outlook for FirstEnergy and its subsidiaries remains stable.

Issuer	Securities	S&P	Moody’s
FirstEnergy	Senior unsecured	BBB-	Baa3
FES	Senior unsecured	BBB	Baa2
OE	Senior unsecured	BBB-	Baa2
CEI	Senior secured	BBB+	Baa2
	Senior unsecured	BBB-	Baa3
TE	Senior unsecured	BBB-	Baa3
Penn	Senior secured	A-	Baa1
JCP&L	Senior unsecured	BBB	Baa2
Met-Ed	Senior unsecured	BBB	Baa2
Penelec	Senior unsecured	BBB	Baa2

Cash Flows From Investing Activities

Net cash flows used in investing activities resulted principally from property additions. Additions for the energy delivery services segment primarily include expenditures related to transmission and distribution facilities. Capital spending by the competitive energy services segment is principally generation-related. The following table summarizes investing activities for the six months ended June 30, 2008 and 2007 by business segment:

Summary of Cash Flows	Property
Used for Investing Activities	Additions			Investments			Other			Total
Sources (Uses)	(In millions)
Six Months Ended June 30, 2008
Energy delivery services	$	(451	)	$	44		$	(4	)	$	(411	)
Competitive energy services		(1,145	)		(9	)		(62	)		(1,216	)
Other		(21	)		49			6			34
Inter-Segment reconciling items		-			(12	)		-			(12	)
Total	$	(1,617	)	$	72		$	(60	)	$	(1,605	)
Six Months Ended June 30, 2007
Energy delivery services	$	(400	)	$	67		$	(1	)	$	(334	)
Competitive energy services		(263	)		(9	)		2			(270	)
Other		(3	)		(25	)		-			(28	)
Inter-Segment reconciling items		(31	)		(14	)		-			(45	)
Total	$	(697	)	$	19		$	1		$	(677	)

Net cash used for investing activities in the first six months of 2008 increased by $928 million compared to the first six months of 2007. The increase was principally due to a $920 million increase in property additions, which reflects AQC system expenditures, the purchase of lessor equity interests in Beaver Valley Unit 2 and Perry and the acquisition of a partially completed natural gas fired generating plant in Fremont, Ohio.  Cash used for other investing activities increased primarily due to the purchase of future vintage emission allowances partially offset by cash proceeds from the sale of telecommunication assets.

21

During the second half of 2008, capital requirements for property additions and capital leases are expected to be approximately $938 million. FirstEnergy and the Companies have additional requirements of approximately $151 million for maturing long-term debt during the remainder of 2008. 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 2008-2012 is expected to be approximately $7.6 billion (excluding nuclear fuel), of which approximately $2.1 billion applies to 2008. Investments for additional nuclear fuel during the 2008-2012 period are estimated to be approximately $1.2 billion, of which about $171 million applies to 2008. During the same periods, FirstEnergy's nuclear fuel investments are expected to be reduced by approximately $895 million and $111 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 June 30, 2008, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.3 billion, as summarized below:

	Maximum
Guarantees and Other Assurances	Exposure
	(In millions)
FirstEnergy Guarantees of Subsidiaries
Energy and Energy-Related Contracts (1)	$	402
LOC (long-term debt) – interest coverage (2)		6
Other (3)		503
		911
Subsidiaries’ Guarantees
Energy and Energy-Related Contracts		86
LOC (long-term debt) – interest coverage (2)		11
FES’ guarantee of FGCO’s sale and leaseback obligations		2,591
		2,688
Surety Bonds		74
LOC (long-term debt) – interest coverage (2)		5
LOC (non-debt) (4)(5)		657
		736
Total Guarantees and Other Assurances	$	4,335

(1) Issued for open-ended terms, with a 10-day termination right by FirstEnergy.

(2) Reflects the interest coverage portion of LOCs issued in support of floating-rate PCRBs with various maturities. The principal amount of floating-rate PCRBs of $2.1 billion is reflected in debt on FirstEnergy’s consolidated balance sheets.

(3) Includes guarantees of $300 million for OVEC obligations and $80 million for nuclear decommissioning funding assurances.

(4) Includes $50 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facility.

(5) Includes approximately $182 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.

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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 the financing or refinancing by subsidiaries 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 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 other FirstEnergy assets. The likelihood is remote that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with 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 June 30, 2008, FirstEnergy’s exposure under these collateral provisions was $542 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.

OFF-BALANCE SHEET ARRANGEMENTS

FES and the Ohio Companies have obligations that are not included on FirstEnergy’s Consolidated Balance Sheets related to sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are satisfied through operating lease payments. The total present value of these sale and leaseback operating lease commitments, net of trust investments, decreased to $1.7 billion as of June 30, 2008, from $2.3 billion as of December 31, 2007, due primarily to NGC’s purchase of certain lessor equity interests in Perry Unit 1 and Beaver Valley Unit 2 (see Note 8).

FirstEnergy has equity ownership interests in certain businesses that are accounted for using the equity method of accounting for investments. 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 changes in the fair value of commodity derivative contracts related to energy production during the three months and six months ended June 30, 2008 are summarized in the following table:

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	Three Months									Six Months
Increase (Decrease) in the Fair Value	Ended June 30, 2008									Ended June 30, 2008
of Commodity Derivative Contracts	Non-Hedge			Hedge			Total			Non-Hedge			Hedge			Total
	(In millions)
Change in the Fair Value of
Commodity Derivative Contracts:
Outstanding net liability at beginning of period	$	(655	)	$	(20	)	$	(675	)	$	(713	)	$	(26	)	$	(739	)
Additions/change in value of existing contracts		(33	)		(13	)		(46	)		(33	)		(24	)		(57	)
Settled contracts		72			(4	)		68			130			13			143
Outstanding net liability at end of period (1)		(616	)		(37	)		(653	)		(616	)		(37	)		(653	)
Non-commodity Net Assets at End of Period:
Interest rate swaps (2)		-			3			3			-			3			3
Net Liabilities - Derivative Contracts at End of Period	$	(616	)	$	(34	)	$	(650	)	$	(616	)	$	(34	)	$	(650	)
Impact of Changes in Commodity Derivative Contracts(3)
Income Statement effects (pre-tax)	$	1		$	-		$	1		$	1		$	-		$	1
Balance Sheet effects:
Other comprehensive income (pre-tax)	$	-		$	(17	)	$	(17	)	$	-		$	(11	)	$	(11	)
Regulatory assets (net)	$	(38	)	$	-		$	(38	)	$	(96	)	$	-		$	(96	)

(1) Includes $616 million in non-hedge commodity derivative contracts (primarily with NUGs) that 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 June 30, 2008 as follows:

Balance Sheet Classification	Non-Hedge			Hedge			Total
	(In millions)
Current-
Other assets	$	1		$	78		$	79
Other liabilities		-			(108	)		(108	)
Non-Current-
Other deferred charges		27			11			38
Other non-current liabilities		(644	)		(15	)		(659	)
Net liabilities	$	(616	)	$	(34	)	$	(650	)

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 (see Note 4). Sources of information for the valuation of commodity derivative contracts as of June 30, 2008 are summarized by year in the following table:

Source of Information
- Fair Value by Contract Year	2008(1)			2009			2010			2011			2012			Thereafter			Total
	(In millions)
Prices actively quoted(2)	$	3		$	4		$	-		$	-		$	-		$	-		$	7
Other external sources(3)		(102	)		(208	)		(159	)		(110	)		-			-			(579	)
Prices based on models		-			-			-			-			(33	)		(48	)		(81	)
Total(4)	$	(99	)	$	(204	)	$	(159	)	$	(110	)	$	(33	)	$	(48	)	$	(653	)

(1)     For the last two quarters of 2008.

(2)     Represents exchange traded NYMEX futures and options.

(3)     Primarily represents contracts based on broker and ICE quotes.

(4)     Includes $616 million in non-hedge commodity derivative contracts (primarily with NUGs) that are offset by a regulatory asset.

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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 June 30, 2008. Based on derivative contracts held as of June 30, 2008, an adverse 10% change in commodity prices would decrease net income by approximately $8 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 June 30, 2008, the debt underlying the $150million outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 5.5%, which the swaps have converted to a current weighted average variable rate of 4.4%.

	June 30, 2008							December 31, 2007
	Notional		Maturity		Fair			Notional		Maturity		Fair
Interest Rate Swaps	Amount		Date		Value			Amount		Date		Value
	(In millions)
Fair value hedges								$	100		2008	$	-
	$	150		2015	$	(3	)		150		2015		(3	)
	$	150			$	(3	)	$	250			$	(3	)

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 anticipated future issuances of fixed-rate, long-term debt securities for one or more of its consolidated subsidiaries in 2008 and 2009, and anticipated variable-rate, short-term debt. 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 and LIBOR rates between the date of hedge inception and the date of the debt issuance. During the first six months of 2008, FirstEnergy entered into forward swaps with an aggregate notional value of $850 million and terminated forward swaps with an aggregate notional value of $650million. FirstEnergy paid $14 million in cash related to the terminations, $5 million of which was deemed ineffective and recognized in current period earnings. The remaining effective portion will be recognized over the terms of the associated future debt. As of June 30, 2008, FirstEnergy had outstanding forward swaps with an aggregate notional amount of $600 million and an aggregate fair value of $6 million.

	June 30, 2008							December 31, 2007
	Notional		Maturity		Fair			Notional		Maturity		Fair
Forward Starting Swaps	Amount		Date		Value			Amount		Date		Value
	(In millions)
Cash flow hedges	$	100		2009	$	(1	)
		100		2010		-
		-		2015		-		$	25		2015	$	(1	)
		350		2018		8			325		2018		(1	)
		50		2020		(1	)		50		2020		(1	)
	$	600			$	6		$	400			$	(3	)

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $1.2 billion and $1.4 billion, as of June 30, 2008 and December 31, 2007, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $118 million reduction in fair value as of June 30, 2008.

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.

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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 June 30, 2008, the largest credit concentration was with one party, currently rated investment grade that represented 9.3% of FirstEnergy’s total approved credit risk.  Within FirstEnergy’s unregulated energy subsidiaries, 98% of credit exposures, net of collateral and reserve, were with investment-grade counterparties as of June 30, 2008.

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 certain 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, the PUCO, the PPUC and the 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 $129 million as of June 30, 2008 (JCP&L - $73 million and Met-Ed - $56 million). Regulatory assets not earning a current return (primarily for certain regulatory transition costs and employee postretirement benefits) are expected to be recovered by 2014 for JCP&L and by 2020 for Met-Ed. The following table discloses regulatory assets by company:

	June 30,		December 31,		Increase
Regulatory Assets*	2008		2007		(Decrease)
	(In millions)
OE	$	683	$	737	$	(54	)
CEI		839		871		(32	)
TE		171		204		(33	)
JCP&L		1,404		1,596		(192	)
Met-Ed		550		495		55
ATSI		36		42		(6	)
Total	$	3,683	$	3,945	$	(262	)

* Penelec had net regulatory liabilities of approximately $79 million and $74 million as of June 30, 2008 and December 31, 2007, respectively. These net regulatory liabilities are included in Other Non-current Liabilities on the Consolidated Balance Sheets.

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Regulatory assets by source are as follows:

	June 30,			December 31,			Increase
Regulatory Assets By Source	2008			2007			(Decrease)
	(In millions)
Regulatory transition costs	$	1,992		$	2,363		$	(371	)
Customer shopping incentives		473			516			(43	)
Customer receivables for future income taxes		290			295			(5	)
Loss on reacquired debt		55			57			(2	)
Employee postretirement benefits		35			39			(4	)
Nuclear decommissioning, decontamination
and spent fuel disposal costs		(94	)		(115	)		21
Asset removal costs		(201	)		(183	)		(18	)
MISO/PJM transmission costs		397			340			57
Fuel costs - RCP		228			220			8
Distribution costs - RCP		405			321			84
Other		103			92			11
Total	$	3,683		$	3,945		$	(262	)

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 (the PUCO, the FERC, the NERC and the U.S. – Canada Power System Outage Task Force) regarding enhancements to regional reliability. The proposed enhancements were divided into two groups:  enhancements that were to be completed in 2004; and enhancements that were to be completed after 2004.  In 2004, FirstEnergy completed all of the enhancements that were recommended for completion in 2004. 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.

As a result of outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU performed a review of JCP&L’s service reliability. On June 9, 2004, the NJBPU approved a stipulation that addresses a third-party consultant’s recommendations on appropriate courses of action necessary to ensure system-wide reliability. The stipulation incorporates the consultant’s focused audit of, and recommendations regarding, JCP&L’s Planning and Operations and Maintenance programs and practices. On June 1, 2005, the consultant completed his work and issued his final report to the NJBPU. On July 14, 2006, JCP&L filed a comprehensive response to the consultant’s report with the NJBPU. JCP&L will complete the remaining substantive work described in the stipulation in 2008.  JCP&L continues to file compliance reports with the NJBPU reflecting JCP&L’s activities associated with implementing the stipulation.

In 2005, Congress amended the Federal Power Act to provide for federally-enforceable mandatory reliability standards. The mandatory reliability standards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on the Companies and ATSI. The NERC is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of its responsibilities to eight regional entities, including ReliabilityFirst Corporation.  All of FirstEnergy’s facilities are located within the ReliabilityFirst region. FirstEnergy actively participates in the NERC and ReliabilityFirst stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards.

FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards.  Nevertheless, it is clear that the NERC, ReliabilityFirst and the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with new or amended standards cannot be determined at this time. However, the 2005 amendments to the Federal Power Act provide that all prudent costs incurred to comply with the new reliability standards be recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties and thus have a material adverse effect on its financial condition, results of operations and cash flows.

In April 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the Midwest ISO region and found it to be in full compliance with all audited reliability standards.  Similarly, ReliabilityFirst has scheduled a compliance audit of FirstEnergy’s bulk-power system within the PJM region in October 2008. FirstEnergy currently does not expect any material adverse financial impact as a result of these audits.

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Ohio

On January 4, 2006, the PUCO issued an order authorizing the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a twenty-five-year period through distribution rates. On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated a provision of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” and remanded the matter to the PUCO for further consideration. On September 10, 2007 the Ohio Companies filed an application with the PUCO that requested the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. On January 9, 2008 the PUCO approved the Ohio Companies’ proposed fuel cost rider to recover increased fuel costs to be incurred in 2008 commencing January 1, 2008 through December 31, 2008, which is expected to be approximately $194 million. In addition, the PUCO ordered the Ohio Companies to file a separate application for an alternate recovery mechanism to collect the 2006 and 2007 deferred fuel costs. On February 8, 2008, the Ohio Companies filed an application proposing to recover $226 million of deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel rider. Recovery of the deferred fuel costs will now be addressed in the Ohio Companies’ comprehensive ESP filing, as described below, unless the MRO is implemented.

On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing to support a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of its investigation into the distribution rate request. In its reports, the PUCO Staff recommended a distribution rate increase in the range of $161 million to $180 million, with $108 million to $127 million for distribution revenue increases and $53 million for recovery of costs deferred under prior cases. On January 3, 2008, the Ohio Companies and intervening parties filed objections to the Staff Reports and on January 10, 2008, the Ohio Companies filed supplemental testimony. Evidentiary hearings began on January 29, 2008 and continued through February 25, 2008. During the evidentiary hearings and filing of briefs, the PUCO Staff decreased their recommended revenue increase to a range of $117 million to $135 million. Additionally, in testimony submitted on February 11, 2008, the PUCO Staff adopted a position regarding interest deferred for RCP-related deferrals, line extension deferrals and transition tax deferrals that, if upheld by the PUCO, would result in the write-off of approximately $51 million of interest costs deferred through June 30, 2008 ($0.10 per share of common stock). The Ohio Companies’ electric distribution rate request is addressed in their comprehensive ESP filing, as described below.

On May 1, 2008, Governor Strickland signed SB221, which became effective on July 31, 2008. The bill requires all utilities to file an ESP with the PUCO. A utility also may file an MRO in which it would have to prove the following objective market criteria:

·   the utility or its transmission service affiliate belongs to a FERC approved RTO, or there is comparable and nondiscriminatory access to the electric transmission grid;

·   the RTO has a market-monitor function and the ability to mitigate market power or the utility’s market conduct, or a similar market monitoring function exists with the ability to identify and monitor market conditions and conduct; and

·   a published source of information is available publicly or through subscription that identifies pricing information for traded electricity products, both on- and off-peak, scheduled for delivery two years into the future.

On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and MRO. The MRO outlines a CBP that would be implemented if the ESP is not approved by the PUCO. Under SB221, a PUCO ruling on the ESP filing is required within 150 days and an MRO decision is required within 90 days. The ESP proposes to phase in new generation rates for customers beginning in 2009 for up to a three-year period and would resolve the Ohio Companies’ collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. Major provisions of the ESP include:

·   a phase-in of new generation rates for up to a three-year period, whereby customers would receive a 10% phase-in credit; related costs (expected to approximate $430 million in 2009, $490 million in 2010 and $550 million in 2011) would be deferred for future collection over a period not to exceed 10 years;

·   a reconcilable rider to recover fuel transportation cost surcharges in excess of $30 million in 2009, $20 million in 2010 and $10 million in 2011;

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·   generation rate adjustments to recover any increase in fuel costs in 2011 over fuel costs incurred in 2010 for FES’ generation assets used to support the ESP;

·   generation rate adjustments to recover the costs of complying with new requirements for certain renewable energy resources, new taxes and new environmental laws or new interpretations of existing laws that take effect after January 1, 2008 and exceed $50 million during the plan period;

·   an RCP fuel rider to recover the 2006 and 2007 deferred fuel costs and carrying charges (described above) over a period not to exceed 25 years;

·   the resolution of outstanding issues pending in the Ohio Companies’ distribution rate case (described above), including annual electric distribution rate increases of $75 million for OE, $34.5 million for CEI and $40.5 million for TE. The new distribution rates would be effective January 1, 2009, for OE and TE and May 1, 2009 for CEI, with a commitment to maintain distribution rates through 2013. CEI also would be authorized to defer $25 million in distribution-related costs incurred from January 1, 2009, through April 30, 2009;

·   an adjustable delivery service improvement rider, effective January 1, 2009, through December 31, 2013, to ensure the Ohio Companies maintain customer standards for service and reliability;

·   the waiver of RTC charges for CEI’s customers as of January 1, 2009, which would result in CEI’s write-off of approximately $485 million of estimated unrecoverable transition costs ($1.01 per share of common stock);

·   the continued recovery of transmission costs, including MISO, ancillary services and congestion charges, through an annually adjusted transmission rider; a separate rider will be established to recover costs incurred annually between May 1st and September 30th for capacity purchases required to meet FERC, NERC, MISO and other applicable standards for planning reserve margin requirements;

·   a deferred transmission cost recovery rider effective January 1, 2009, through December 31, 2010 to recover transmission costs deferred by the Ohio Companies in 2005 and accumulated carrying charges through December 31, 2008; a deferred distribution cost recovery rider effective January 1, 2011, to recover distribution costs deferred under the RCP, CEI’s additional $25 million of cost deferrals in 2009, line extension deferrals and transition tax deferrals;

·   the deferral of annual storm damage expenses in excess of $13.9 million, certain line extension costs, as well as depreciation, property tax obligations and post in-service carrying charges on energy delivery capital investments for reliability and system efficiency placed in service after December 31, 2008. Effective January 1, 2014, a rider will be established to collect the deferred balance and associated carrying charges over a 10-year period; and

·   a commitment by the Ohio Companies to invest in aggregate at least $1 billion in capital improvements in their energy delivery systems through 2013 and fund $25 million for energy efficiency programs and $25 million for economic development and job retention programs through 2013.

The Ohio Companies’ MRO filing outlines a CBP for providing retail generation supply if the ESP is not approved and implemented. The CBP would use a “slice-of-system” approach where suppliers bid on tranches (approximately 100 MW) of the Ohio Companies’ total customer load. The Ohio Companies have requested PUCO approval of the MRO application by late October 2008, to allow for the necessary time to conduct the CBP in order for rates to be effective January 1, 2009.  The Ohio Companies included an interim pricing proposal as part of their ESP filing, if additional time is necessary for final PUCO approval of either the ESP or MRO. FES will be required to obtain FERC authorization to sell electric capacity or energy to the Ohio Companies under the ESP or MRO, unless a waiver is obtained.

Pennsylvania

Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. The fixed price under the agreement is expected to remain below wholesale market prices during the term of the 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 their 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.

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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. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec 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 merger savings, with the comprehensive transition 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, 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 to 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 costs. 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).

On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania 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. From June through October 2007, initial responsive and reply briefs were filed by various parties. Oral arguments are scheduled to take place in September 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the results of operations of Met-Ed, Penelec and FirstEnergy.

On May 22, 2008, the PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. Various intervenors filed complaints against Met-Ed’s and Penelec’s TSC filings.  In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing the company to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted with hearings for both companies scheduled to begin in January 2009. The TSCs include a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received approval from the PPUC of a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010.

On March 13, 2008, the PPUC approved the residential procurement process in Penn’s Joint Petition for Settlement. This RFP process calls for load-following, full-requirements contracts for default service procurement for residential customers for the period covering June 1, 2008 through May 31, 2011. The PPUC had previously approved the default service procurement processes for commercial and industrial customers. The default service procurement for small commercial customers was conducted through multiple RFPs, while the default service procurement for large commercial and industrial customers will utilize hourly pricing. Bids in the two RFPs for small commercial load were approved by the PPUC on February 22, 2008, and March 20, 2008. On March 28, 2008, Penn filed compliance tariffs with the new default service generation rates based on the approved RFP bids for small commercial customers which the PPUC then certified on April 4, 2008. Bids on the two RFPs for residential customers’ load were approved by the PPUC on April 16, 2008 and May 16, 2008. On May 20, 2008, Penn filed compliance tariffs with the new default service generation rates based on the approved RFP bids for residential customers which the PPUC certified on May 21, 2008. The new rates were effective June 1, 2008.

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On February 1, 2007, the Governor of Pennsylvania proposed an 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 and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and a three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. Neither chamber has formally considered the other’s bill. On February 12, 2008, the Pennsylvania House passed House Bill 2200 which provides for energy efficiency and demand management programs and targets as well as the installation of smart meters within ten years. As part of the 2008 state budget negotiations, the Alternative Energy Investment Act was enacted creating a $650 million alternative energy fund to increase the development and use of alternative and renewable energy, improve energy efficiency and reduce energy consumption. Other legislation has been introduced to address generation procurement, expiration of rate caps, conservation and renewable energy; however, consideration of these issues was postponed until the legislature returns to session in fall 2008. The final form of this pending legislation is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations. However, Met-Ed and Penelec intend to file rate mitigation plans with the PPUC later this year.

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 June 30, 2008, the accumulated deferred cost balance totaled approximately $293 million.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting 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. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. 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 the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that 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. The NJBPU Staff circulated revised drafts of the proposal to interested stakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU accepted proposed rules for publication in the New Jersey Register on March 17, 2008. A public hearing on these proposed rules was held on April 23, 2008 and comments from interested parties were submitted by May 19, 2008.

New Jersey statutes require that the state periodically undertake a planning process, known as the 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 through the creation of a number of working groups to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. In addition, public stakeholder meetings were held in 2006, 2007 and the first half of 2008.

On April 17, 2008, a draft EMP was released for public comment. The draft EMP establishes five major goals:

·   maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020;

·   reduce peak demand for electricity by 5,700 MW by 2020;

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·   meet 22.5% of the state’s electricity needs with renewable energy by 2020;

·   develop low carbon emitting, efficient power plants and close the gap between the supply and demand for electricity; and

·   invest in innovative clean energy technologies and businesses to stimulate the industry’s growth in New Jersey.

Following the public hearings and comment period which extended into July 2008, a final EMP will be issued to be followed by appropriate legislation and regulation as necessary. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation or regulation may have on its operations or those of JCP&L.

FERC Matters

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or “SECA”) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, 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 by year-end 2008.  In the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order.

PJM Transmission Rate Design

On January 31, 2005, certain PJM transmission owners made 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. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design; notably AEP, which proposed to create a "postage stamp", or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order finding that the PJM transmission owners’ existing “license plate” or zonal 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, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones 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. The 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.

On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. The FERC’s orders on PJM rate design will prevent the allocation of a portion of the revenue requirement 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 the costs of future transmission to be recovered from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding Judge. The FERC’s action on the settlement agreement is pending. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. Reply briefs and briefs on exceptions are due in the merchant proceeding in July and August, respectively, with an initial decision by the Presiding Judge to follow. On February 11, 2008, AEP appealed the FERC’s April 19, 2007 and January 31, 2008 orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit.

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Post Transition Period Rate Design

The FERC had directed MISO, PJM, and the respective transmission owners to make filings on or before August 1, 2007 to reevaluate transmission rate design within MISO, and between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the vast majority of transmission owners, including FirstEnergy affiliates, which proposed to retain the existing transmission rate design. These filings were approved by the FERC on January 31, 2008. As a result of the FERC’s approval, the rates charged to FirstEnergy’s load-serving affiliates for transmission service over existing transmission facilities in MISO and PJM are unchanged. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and higher transmission facilities across the entire MISO footprint (known as the RECB methodology) be retained.

On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have the FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “Super Region” that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers. Lower voltage facilities would continue to be recovered in the local utility transmission rate zone through a license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On January 31, 2008, the FERC issued an order denying the complaint. A rehearing request by AEP is pending before the FERC.

Distribution of MISO Network Service Revenues

Effective February 1, 2008, the MISO Transmission Owners Agreement provides for a change in the method of distributing transmission revenues among the transmission owners. MISO and a majority of the MISO transmission owners filed on December 3, 2007 to change the MISO tariff to clarify, for purposes of distributing network transmission revenue to the transmission owners, that all network transmission service revenues, whether collected by MISO or directly by the transmission owner, are included in the revenue distribution calculation.  This clarification was necessary because some network transmission service revenues are collected and retained by transmission owners in states where retail choice does not exist, and their “unbundled” retail load is currently exempt from MISO network service charges. The tariff changes filed with the FERC ensure that revenues collected by transmission owners from bundled load are taken into account in the revenue distribution calculation, and that transmission owners with bundled load do not collect more than their revenue requirements. Absent the changes, transmission owners, and ultimately their customers, with unbundled load or in retail choice states, such as ATSI, would subsidize transmission owners with bundled load, who would collect their revenue requirement from bundled load, plus share in revenues collected by MISO from unbundled customers. This would result in a large revenue shortfall for ATSI, which would eventually be passed on to customers in the form of higher transmission rates as calculated pursuant to ATSI’s Attachment O formula under the MISO tariff.

Numerous parties filed in support of the tariff changes, including the public service commissions of Michigan, Ohio and Wisconsin. Ameren filed a protest on December 26, 2007, arguing that the December 3, 2007 filing violates the MISO Transmission Owners’ Agreement as well as an agreement among Ameren (Union Electric), MISO, and the Missouri Public Service Commission, which provides that Union Electric’s bundled load cannot be charged by MISO for network service. On February 1, 2008, the FERC issued an order conditionally accepting the tariff amendment subject to a minor compliance filing, which was made on March 3, 2008. This order ensures that ATSI will continue to receive transmission revenues from MISO equivalent to its transmission revenue requirement. A rehearing request by Ameren is pending before the FERC.

On February 1, 2008, MISO filed a request to continue using the existing revenue distribution methodology on an interim basis pending amendment of the MISO Transmission Owners’ Agreement. This request was accepted by the FERC on March 13, 2008. On that same day, MISO and the MISO transmission owners made a filing to amend the Transmission Owners’ Agreement to effectively continue the distribution of transmission revenues that was in effect prior to February 1, 2008. On May 12, 2008, the FERC issued an order approving this amendment.

MISO Ancillary Services Market and Balancing Area Consolidation

MISO made a filing on September 14, 2007 to establish an ASM for regulation, spinning and supplemental reserves, to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region. This filing would permit load serving entities to purchase their operating reserve requirements in a competitive market. FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas. On February 25, 2008, the FERC issued an order approving the ASM subject to certain compliance filings. Numerous parties filed requests for rehearing on March 26, 2008. On June 23, 2008, the FERC issued an order granting in part and denying in part rehearing. MISO has since notified the FERC that the start of its ASM will be delayed until September 9, 2008.

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On February 29, 2008, MISO submitted a compliance filing setting forth MISO’s Readiness Advisor ASM and Consolidated Balancing Authority Initiative Verification plan and status and Real-Time Operations ASM Reversion plan. FERC action on this compliance filing remains pending. On March 26, 2008, MISO submitted a tariff filing in compliance with the FERC’s 30-day directives in the February 25 order. Numerous parties submitted comments and protests on April 16, 2008. The FERC issued an order accepting the revisions pending further compliance on June 23, 2008. On April 25, 2008, MISO submitted a tariff filing in compliance with the FERC’s 60-day directives in the February 25 order. FERC action on this compliance filing remains pending. On May 23, 2008, MISO submitted its amended Balancing Authority Agreement. On July 21, 2008, the FERC issued an order conditionally accepting the amended Balancing Authority Agreement and requiring a further compliance filing.

Interconnection Agreement with AMP-Ohio

On May 4, 2007, AMP-Ohio filed a complaint in Franklin County, Ohio Common Pleas Court against FirstEnergy and TE seeking a declaratory judgment that the defendants may not terminate certain portions of a wholesale power Interconnection Agreement dated May 1, 1989 between AMP-Ohio and TE, nor further modify the rates and charges for power under that agreement. TE has served notice of termination of the Interconnection Agreement on AMP-Ohio to be effective December 31, 2008. AMP-Ohio claims that FirstEnergy, on behalf of TE, waived any right to terminate the Interconnection Agreement according to the terms of a June 6, 1997 merger settlement agreement with AMP-Ohio. Both the Interconnection Agreement and merger settlement agreement were approved by the FERC. On June 15, 2007, TE filed notice of removal of the case to United States District Court for the Southern District of Ohio. On July 11, 2007, TE moved to dismiss on the grounds that the FERC has exclusive jurisdiction over the subject matter of the complaint, or alternatively, primary jurisdiction over this matter. Responsive pleadings were filed by both parties and on March 31, 2008, the district court issued an order dismissing the matter for lack of subject matter jurisdiction. However, AMP-Ohio informed TE that it continues to object to cancellation of the power sales provisions of the Interconnection Agreement.

On May 29, 2008, TE filed with the FERC a proposed Notice of Cancellation effective midnight December 31, 2008, of the Interconnection Agreement with AMP-Ohio. AMP-Ohio protested this filing. TE also filed a Petition for Declaratory Order seeking a FERC ruling, in the alternative if cancellation is not accepted, of TE's right to file for an increase in rates effective January 1, 2009, for power provided to AMP-Ohio under the Interconnection Agreement. AMP-Ohio filed a pleading agreeing that TE may seek an increase in rates, but arguing that any increase is limited to the cost of generation owned by TE affiliates. TE has requested FERC action on both filings and expects the FERC to act on this request in the third quarter of 2008.

Duquesne’s Request to Withdraw from PJM

On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join MISO. In its filing, Duquesne asked the FERC to be relieved of certain capacity payment obligations to PJM for capacity auctions conducted prior to its departure from PJM, but covering service for planning periods through May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is to avoid paying future obligations created by PJM’s forward capacity market. FirstEnergy believes that Duquesne’s filing did not identify or address numerous legal, financial or operational issues that are implicated or affected directly by Duquesne’s proposal. Consequently, FirstEnergy submitted responsive filings that, while conceding Duquesne’s rights to exit PJM, contested various aspects of Duquesne’s proposal. FirstEnergy particularly focused on Duquesne’s proposal that it be allowed to exit PJM without payment of its share of existing capacity market commitments. FirstEnergy also objected to Duquesne’s failure to address the firm transmission service requirements that would be necessary for FirstEnergy to continue to use the Beaver Valley Plant to meet existing commitments in the PJM capacity markets and to serve native load. Other market participants also submitted filings contesting Duquesne’s plans.

On January 17, 2008, the FERC conditionally approved Duquesne’s request to exit PJM. Among other conditions, the FERC obligated Duquesne to pay the PJM capacity obligations through May 31, 2011. The FERC’s order took notice of the numerous transmission and other issues raised by FirstEnergy and other parties to the proceeding, but did not provide any responsive rulings or other guidance. Rather, the FERC ordered Duquesne to make a compliance filing in forty-five days detailing how Duquesne will satisfy its obligations under the PJM Transmission Owners’ Agreement. The FERC likewise directed MISO to submit detailed plans to integrate Duquesne into MISO. Finally, the FERC directed MISO and PJM to work together to resolve the substantive and procedural issues implicated by Duquesne’s transition into MISO. These issues remain unresolved. If Duquesne satisfies all of the obligations set by the FERC, its planned transition date is October 1, 2008.  On July 3, 2008, Duquesne and MISO filed a proposed plan for integrating Duquesne into MISO.  On July 24, 2008, numerous parties filed comments and protests to the proposed plan. FirstEnergy filed comments identifying numerous issues that must be addressed and resolved before Duquesne can transition to MISO. FirstEnergy continues to evaluate the impact of Duquesne’s withdrawal from PJM on its operations and financial condition; however, the full consequences cannot be determined until the FERC rules on the pending issues.

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On March 18, 2008, the PJM Power Providers Group filed a request for emergency clarification regarding whether Duquesne-zone generators (including the Beaver Valley Plant) could participate in PJM’s May 2008 auction for the 2011-2012 RPM delivery year. FirstEnergy and the other Duquesne-zone generators filed responsive pleadings. On April 18, 2008, the FERC issued its Order on Motion for Emergency Clarification, wherein the FERC ruled that although the status of the Duquesne-zone generators will change to “External Resource” upon Duquesne’s exit from PJM, these generators could contract with PJM for the transmission reservations necessary to participate in the May 2008 auction. FirstEnergy has complied with the FERC’s order by obtaining executed transmission service agreements for firm point-to-point transmission service for the 2011-2012 delivery year and, as such, FirstEnergy satisfied the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction. Notwithstanding these events, on April 30, 2008 and May 1, 2008, certain members of the PJM Power Providers Group filed further pleadings on these issues. On May 2, 2008, FirstEnergy filed a responsive pleading. Given that the FERC outlined the conditions under which FirstEnergy could bid the unit into the auction and FirstEnergy complied with the FERC’s conditions, FirstEnergy does not anticipate that the FERC will grant the relief requested in the pleadings.  Based on this expectation, FirstEnergy believes that the auction results would not be changed.

Complaint against PJM RPM Auction

On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act. Most of the parties comprising the RPM Buyers group were parties to the settlement approved by the FERC that established the RPM. In the complaint, the RPM Buyers request that the total projected payments to RPM sellers for the three auctions at issue be materially reduced. On July 11, 2008, PJM filed its answer to the complaint, in which it denied the allegation that the rates are unjust and unreasonable. Also on that date, FirstEnergy filed a motion to intervene. 

If the FERC were to rule unfavorably on this matter, the impact for the period ended June 30, 2008, would not be material to FirstEnergy’s results of operations, cash flows or financial position, as FES only began collecting RPM revenues for the Beaver Valley Power Station on June 1, 2008.  However, such an unfavorable ruling by the FERC could have a material adverse impact on the revenues of the Beaver Valley Power Station in subsequent periods if these proceedings were to result in a significant loss of FES’ RPM revenues.

FES believes that the FERC is unlikely to grant the relief sought in the RPM Buyers’ complaint, since it largely deals with legal issues concerning the fundamentals of the RPM markets that are already at issue in a separate D.C. Circuit Court appellate proceeding. Nevertheless, FES is unable to predict the outcome of these proceedings or the resulting effect on FirstEnergy’s or FES’ results of operations, cash flows or financial position.

MISO Resource Adequacy Proposal

MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load serving entities such as the Ohio Companies, Penn Power, and FES. This requirement is proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for load serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for load serving entities in its state. FirstEnergy believes the proposal promotes a mechanism that will result in commitments from both load-serving entities and resources, including both generation and demand side resources, that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were filed on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, 2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC’s March 26 Order. On May 27, 2008, MISO submitted a compliance filing to address issues associated with planning reserve margins. On June 17, 2008, various parties submitted comments and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific issues that must be clarified and addressed. On June 25, 2008, MISO submitted a second compliance filing establishing the enforcement mechanism for the reserve margin requirement which establishes deficiency payments for load serving entities that do not meet the resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing. A FERC decision on this filing is expected this fall.

Organized Wholesale Power Markets

On February 21, 2008, the FERC issued a NOPR through which it proposes to adopt new rules that it states will “improve operations in organized electric markets, boost competition and bring additional benefits to consumers.” The proposed rule addresses demand response and market pricing during reserve shortages, long-term power contracting, market-monitoring policies, and responsiveness of RTOs and ISOs to stakeholders and customers. FirstEnergy does not believe that the proposed rule will have a significant impact on its operations. Comments on the NOPR were filed on April 21, 2008.

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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. FirstEnergy estimates capital expenditures for environmental compliance of approximately $1.4 billion for the period 2008-2012.

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 the 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 CAA. FirstEnergy has disputed those alleged violations based on its CAA permit, the Ohio SIP and other information provided to the EPA 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. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding emission limits applicable to the common stack for Bay Shore Units 2, 3 and 4.

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. NOX 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 NOX reductions at FirstEnergy's facilities. The EPA's NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX 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 NOX emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.

On April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. Subsequently, on May 8, 2007, the EPA proposed to revise the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR.   The EPA has not yet issued a final regulation. FGCO’s future cost of compliance with those regulations may be substantial and will depend on how they are ultimately implemented.

On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October 18, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy filed a motion to dismiss claims alleging a public nuisance. On April 24, 2008, the Court denied the motion to dismiss, but also ruled that monetary damages could not be recovered under the public nuisance claim.

On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed.  Specifically, New Jersey alleges that "modifications" at Portland Units 1 and 2 occurred between 1980 and 1995 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. On March 14, 2008, Met-Ed filed a motion to dismiss the citizen suit claims against it and a stipulation in which the parties agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the United States District Court. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed.  Met-Ed is unable to predict the outcome of this matter.

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On June 11, 2008, the EPA issued a Notice and Finding of Violation to MEW alleging that "modifications" at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program. MEW is seeking indemnification from Penelec, which was the co-owner (along with New York State Electric and Gas Company) and operator of the Homer City Power Station prior to its sale in 1999.  Although it remains liable for civil or criminal penalties and fines that may be assessed relating to events prior to the sale of the Homer City Power Station in 1999, the scope of Penelec’s indemnity obligation to and from MEW is disputed.  Penelec is unable to predict the outcome of this matter.

On May 16, 2008, FGCO received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an ACO modifying that request and setting forth a schedule for FGCO’s response. FGCO intends to fully comply with the ACO, but, at this time, is unable to predict the outcome of this matter.

National Ambient Air Quality Standards

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 would have required reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2), ultimately capping SO2 emissions in affected states to just 2.5 million tons annually and NOX emissions to just 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” The court ruling also vacated the CAIR regional cap-and-trade programs for SO2 and NOX, which is currently not expected to, but may, materially impair the value of emissions allowances obtained for future compliance. The future cost of compliance with these regulations may be substantial and will depend on the action taken by the EPA or Congress in response to the Court’s ruling.

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, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the court vacated the CAMR ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA petitioned for rehearing by the entire court, which denied the petition on May 20, 2008.  The EPA must now petition for United States Supreme Court review of that ruling or take regulatory action to promulgate new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with mercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately implemented.

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. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant, FirstEnergy’s only Pennsylvania coal-fired power plant, until 2015, if at all.

W. H. Sammis Plant

In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W.H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case, along with seven other similar cases, are referred to as the NSR cases.

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On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR 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 NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield 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 consent decree are currently estimated to be $1.3 billion for 2008-2012 ($650 million of which is expected to be spent during 2008, with the largest portion of the remaining $650 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above.

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 2012. The United States signed the Kyoto Protocol in 1998 but it was never submitted 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. Also, in an April 16, 2008 speech, President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition, 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.

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level.  At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the Senate Environmental and Public Works Committees have passed one such bill. 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 CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. On July 11, 2008, the EPA released an Advance Notice of Proposed Rulemaking, soliciting input from the public on the effects of climate change and the potential ramifications of regulation of CO2 under the CAA.

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.

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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 United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 14, 2008, the Supreme Court of the United States granted a petition for a writ of certiorari to review one significant aspect of the Second Circuit Court’s opinion which is whether Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. FirstEnergy is studying various control options and their costs and effectiveness. Depending on the results of such studies, the outcome of the Supreme Court’s review of the Second Circuit’s decision, the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs 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 non-hazardous waste.

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of June 30, 2008, FirstEnergy had approximately $2.0 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, 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 (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seeks 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 may be liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of June 30, 2008, 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. Total liabilities of approximately $95 million (JCP&L - $68 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through June 30, 2008. Included in the total for JCP&L are accrued liabilities of approximately $57 million for environmental remediation of former manufactured gas plants in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

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.

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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 in July 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, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. 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, in March 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. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007.  Proceedings are continuing in the Superior Court and a case management conference with the presiding Judge was held on June 13, 2008.  At that conference, the plaintiffs stated their intent to drop their efforts to create a class-wide damage model and, instead of dismissing the class action, expressed their desire for a bifurcated trial on liability and damages.  The judge directed the plaintiffs to indicate, on or before August 22, 2008, how they intend to proceed under this scenario.  Thereafter, the judge expects to hold another pretrial conference to address plaintiffs' proposed procedure.FirstEnergy is defending this action but is unable to predict the outcome of this matter.  No liability has been accrued as of June 30, 2008.

Nuclear Plant Matters

On May 14, 2007, the Office of Enforcement of the NRC issued a DFI to FENOC, following FENOC’s reply to an April 2, 2007 NRC request for information about two reports prepared by expert witnesses for an insurance arbitration (the insurance claim was subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse. The NRC indicated that this information was needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s DFI reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. FENOC submitted a supplemental response clarifying certain aspects of the DFI response to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRC’s Office of Enforcement after it completes the key commitments embodied in the NRC’s order. FENOC has conducted the employee training required by one portion of the confirmatory order and a consultant has performed follow-up reviews to ensure the effectiveness of that training.  The NRC continues to monitor FENOC’s compliance with all the commitments made in the confirmatory order.

In August 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The NRC is required by statute to provide an opportunity for members of the public to request a hearing on the application. No members of the public, however, requested a hearing on the Beaver Valley license renewal application. The NRC is expected to issue its draft supplemental Environmental Impact Statement and Safety Evaluation Report with open items in 2008. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and expects to obtain renewed licenses for the Beaver Valley Power Station in 2009. If renewed licenses are issued by the NRC, the Beaver Valley Power Station’s licenses would be extended until 2036 and 2047 for Units 1 and 2, respectively.

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.

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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. On July 30, 2007, plaintiffs’ counsel voluntarily withdrew their request for reconsideration of the April 5, 2007 Court order denying class certification and the Court heard oral argument on the plaintiffs’ motion to amend their complaint, which OE opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend their complaint. The plaintiffs have appealed the Court’s denial of the motion for certification as a class action and motion to amend their complaint.

On July 22, 2008 and July 23, 2008, three complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania as well as in the Beaver County Court of Common Pleas seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner,” one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints.

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. A final order identifying the individual damage amounts was issued on October 31, 2007. The award appeal process was initiated. The union filed a motion with the federal court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008. Oral arguments have been requested and are expected to take place in fall 2008. JCP&L recognized a liability for the potential $16 million award in 2005.

The union employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. The parties are continuing to bargain with the assistance of a federal mediator. FirstEnergy has a strike mitigation plan ready in the event of a strike.

FirstEnergy accrues legal 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. 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.

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

SFAS 141(R) – “Business Combinations”

In December 2007, the FASB issued SFAS 141(R), which: (i) requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; (ii) establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and (iii) requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FirstEnergy that close after January 1, 2009. In addition, the Standard also affects the accounting for changes in tax valuation allowances made after January 1, 2009, that were established as part of a business combination prior to the implementation of this Standard. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial statements.

SFAS 160 - “Non-controlling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51”

In December 2007, the FASB issued SFAS 160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. The Statement is not expected to have a material impact on FirstEnergy’s financial statements.

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SFAS 161 - “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133”

In March 2008, the FASB issued SFAS 161 that enhances the current disclosure framework for derivative instruments and hedging activities. The Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. The FASB believes that additional required disclosure of the fair values of derivative instruments and their gains and losses in a tabular format will provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features is designed to provide information on the potential effect on an entity’s liquidity from using derivatives. This Statement also requires cross-referencing within the footnotes to help users of financial statements locate important information about derivative instruments. The Statement is effective for fiscal years beginning on or after December 15, 2008. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial statements.

SFAS 162 - “The Hierarchy of Generally Accepted Accounting Principles”

In May 2008, the FASB issued SFAS 162, which is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with GAAP. The FASB believes that the GAAP hierarchy should be directed to reporting entities, not the independent auditors, because reporting entities are responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP. This Statement is effective 60 days following the SEC’s approval of the PCAOB amendments to U.S. Auditing Standards Section 411, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles, which has not yet occurred. The Statement will not have an impact on FirstEnergy’s financial statements.

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Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of FirstEnergy Corp.:

We have reviewed the accompanying consolidated balance sheet of FirstEnergy Corp. and its subsidiaries as of June 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2008 and 2007 and the consolidated statement of cash flows for the six-month periods ended June 30, 2008 and 2007. 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 (United States), 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, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, 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, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

August 7, 2008

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FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months						Six Months
	Ended June 30						Ended June 30
	2008			2007			2008			2007
	(In millions, except per share amounts)
REVENUES:
Electric utilities	$	2,865		$	2,718		$	5,778		$	5,377
Unregulated businesses		380			391			744			705
Total revenues *		3,245			3,109			6,522			6,082
EXPENSES:
Fuel and purchased power		1,386			1,185			2,714			2,306
Other operating expenses		781			750			1,581			1,499
Provision for depreciation		168			159			332			315
Amortization of regulatory assets		246			246			504			497
Deferral of new regulatory assets		(98	)		(148	)		(203	)		(292	)
General taxes		180			189			395			392
Total expenses		2,663			2,381			5,323			4,717
OPERATING INCOME		582			728			1,199			1,365
OTHER INCOME (EXPENSE):
Investment income		16			30			33			63
Interest expense		(188	)		(205	)		(367	)		(390	)
Capitalized interest		13			7			21			12
Total other expense		(159	)		(168	)		(313	)		(315	)
INCOME BEFORE INCOME TAXES		423			560			886			1,050
INCOME TAXES		160			222			347			422
NET INCOME	$	263		$	338		$	539		$	628
BASIC EARNINGS PER SHARE OF COMMON STOCK	$	0.86		$	1.11		$	1.77		$	2.03
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING		304			304			304			309
DILUTED EARNINGS PER SHARE OF COMMON STOCK	$	0.85		$	1.10		$	1.75		$	2.01
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING		307			308			307			313
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	-		$	-		$	0.55		$	0.50
* Includes excise tax collections of $100 million and $101 million in the three months ended June 30, 2008 and 2007, respectively, and
$214 million and $209 million in the six months ended June 2008 and 2007, respectively.
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.

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FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
	Three Months						Six Months
	Ended June 30						Ended June 30
	2008			2007			2008			2007
	(In millions)
NET INCOME	$	263		$	338		$	539		$	628
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(20	)		(11	)		(40	)		(22	)
Unrealized gain (loss) on derivative hedges		8			(1	)		(5	)		20
Change in unrealized gain on available for sale securities		(23	)		46			(81	)		63
Other comprehensive income (loss)		(35	)		34			(126	)		61
Income tax expense (benefit) related to other
comprehensive income		(14	)		10			(47	)		19
Other comprehensive income (loss), net of tax		(21	)		24			(79	)		42
COMPREHENSIVE INCOME	$	242		$	362		$	460		$	670
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
these statements.

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FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,			December 31,
	2008			2007
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	70		$	129
Receivables-
Customers (less accumulated provisions of $29 million and
$36 million, respectively, for uncollectible accounts)		1,365			1,256
Other (less accumulated provisions of $3 million and
$22 million, respectively, for uncollectible accounts)		188			165
Materials and supplies, at average cost		583			521
Prepayments and other		629			159
		2,835			2,230
PROPERTY, PLANT AND EQUIPMENT:
In service		25,744			24,619
Less - Accumulated provision for depreciation		10,606			10,348
		15,138			14,271
Construction work in progress		1,565			1,112
		16,703			15,383
INVESTMENTS:
Nuclear plant decommissioning trusts		1,988			2,127
Investments in lease obligation bonds		675			717
Other		752			754
		3,415			3,598
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		5,606			5,607
Regulatory assets		3,683			3,945
Pension assets		745			700
Other		558			605
		10,592			10,857
	$	33,545		$	32,068
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	2,508		$	2,014
Short-term borrowings		2,608			903
Accounts payable		930			777
Accrued taxes		231			408
Other		860			1,046
		7,137			5,148
CAPITALIZATION:
Common stockholders’ equity-
Common stock, $.10 par value, authorized 375,000,000 shares-
304,835,407 outstanding		31			31
Other paid-in capital		5,461			5,509
Accumulated other comprehensive loss		(129	)		(50	)
Retained earnings		3,858			3,487
Total common stockholders' equity		9,221			8,977
Long-term debt and other long-term obligations		8,603			8,869
		17,824			17,846
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		2,724			2,671
Asset retirement obligations		1,307			1,267
Deferred gain on sale and leaseback transaction		1,043			1,060
Power purchase contract loss liability		644			750
Retirement benefits		919			894
Lease market valuation liability		330			663
Other		1,617			1,769
		8,584			9,074
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)
	$	33,545		$	32,068
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these
balance sheets.

46

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months
	Ended June 30
	2008			2007
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	539		$	628
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		332			315
Amortization of regulatory assets		504			497
Deferral of new regulatory assets		(203	)		(292	)
Nuclear fuel and lease amortization		51			50
Deferred purchased power and other costs		(119	)		(185	)
Deferred income taxes and investment tax credits, net		129			85
Investment impairment		38			12
Deferred rents and lease market valuation liability		(101	)		(92	)
Accrued compensation and retirement benefits		(140	)		(69	)
Stock-based compensation		(72	)		(37	)
Commodity derivative transactions, net		3			4
Gain on asset sales		(41	)		(12	)
Cash collateral		67			(19	)
Pension trust contribution		-			(300	)
Decrease (increase) in operating assets-
Receivables		(136	)		(282	)
Materials and supplies		(31	)		22
Prepayments and other current assets		(399	)		(157	)
Increase (decrease) in operating liabilities-
Accounts payable		152			28
Accrued taxes		(190	)		(17	)
Electric service prepayment programs		(39	)		(36	)
Other		(28	)		27
Net cash provided from operating activities		316			170
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		549			800
Short-term borrowings, net		1,705			1,308
Redemptions and Repayments-
Common stock		-			(918	)
Long-term debt		(720	)		(471	)
Net controlled disbursement activity		8			32
Stock-based compensation tax benefit		23			14
Common stock dividend payments		(335	)		(311	)
Net cash provided from financing activities		1,230			454
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(1,617	)		(697	)
Proceeds from asset sales		56			12
Sales of investment securities held in trusts		726			583
Purchases of investment securities held in trusts		(775	)		(630	)
Cash investments		65			54
Other		(60	)		1
Net cash used for investing activities		(1,605	)		(677	)
Net decrease in cash and cash equivalents		(59	)		(53	)
Cash and cash equivalents at beginning of period		129			90
Cash and cash equivalents at end of period	$	70		$	37
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral
part of these statements.

47

FIRSTENERGY SOLUTIONS CORP.

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

FES is a wholly owned subsidiary of FirstEnergy. FES provides energy-related products and services primarily in Ohio, Pennsylvania, Michigan and Maryland, and through its subsidiaries, FGCO and NGC, owns or leases and operates FirstEnergy’s fossil and hydroelectric generation facilities and owns FirstEnergy’s nuclear generation facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities.

FES’ revenues are primarily from the sale of electricity (provided from FES’ generating facilities and through purchased power arrangements) to affiliated utility companies to meet all or a portion of their PLR and default service requirements. These affiliated power sales include a full-requirements PSA with OE, CEI and TE to supply each of their default service obligations through 2008, at prices that take into consideration their respective PUCO-authorized billing rates. FES also has a partial requirements wholesale power sales agreement with its affiliates, Met-Ed and Penelec, to supply a portion of each of their respective default service obligations at fixed prices through 2010. The fixed prices under the partial requirements agreement are expected to remain below wholesale market prices during the term of the agreement. FES also supplies a portion of Penn’s default service requirements at market-based rates as a result of Penn’s 2008 competitive solicitations. FES’ existing contractual obligations to Penn expire on May 31, 2009, but could continue if FES successfully bids in future competitive solicitations. FES’ revenues also include competitive retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania, Maryland and Michigan.

Results of Operations

In the first six months of 2008, net income decreased to $158million from $254million in the same period in 2007. The decrease in net income was primarily due to higher fuel and other operating expenses, partially offset by lower purchased power costs and higher revenues.

Revenues

Revenues increased by $83million in the first six months of 2008 compared to the same period in 2007 due to increases in revenues from non-affiliated and affiliated wholesale sales, partially offset by lower retail generation sales. Retail generation sales revenues decreased as a result of decreased sales in the PJM market partially offset by increased sales in the MISO market. Lower sales in the PJM market were primarily due to lower contract renewals for commercial and industrial customers. Increased sales in the MISO market were primarily due to FES capturing more shopping customers in Penn’s service territory, partially offset by lower customer usage. Non-affiliated wholesale revenues increased as a result of higher spot market prices in PJM, partially offset by decreased sales volumes in MISO.

The increase in affiliated company wholesale sales was due to higher unit prices for the Ohio Companies and increased sales volumes to the Pennsylvania Companies, partially offset by lower unit prices for the Pennsylvania Companies reflecting a lower composite rate. Higher unit prices on sales to the Ohio Companies resulted from the provision of the full-requirements PSA under which PSA rates reflect the increase in the Ohio Companies’ retail generation rates. The higher sales to the Pennsylvania Companies were due to increased Met-Ed and Penelec generation sales requirements, partially offset by lower sales to Penn due to decreased default service requirements in the first six months of 2008 compared to the first six months of 2007.

Transmission revenue increased $21 million due to higher transmission rates in MISO and PJM. Other revenue increased by $8 million principally due to revenue from affiliated companies for the lessor equity interests in Beaver Valley Unit 2 and Perry that were acquired by NGC during the second quarter of 2008.

Changes in revenues in the first six months of 2008 from the same period of 2007 are summarized below:

	Six  Months Ended
	June 30,				Increase
Revenues by Type of Service	2008		2007		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	315	$	359	$	(44	)
Wholesale		298		276		22
Total Non-Affiliated Generation Sales		613		635		(22	)
Affiliated Generation Sales		1,480		1,404		76
Transmission		66		45		21
Other		11		3		8
Total Revenues	$	2,170	$	2,087	$	83

48

The following tables summarize the price and volume factors contributing to changes in revenues from non-affiliated and affiliated generation sales in the first six months of 2008 compared to the same period last year:

	Increase
Source of Change in Non-Affiliated Generation Revenues	(Decrease)
	(In millions)
Retail:
Effect of 12.8% decrease in sales volumes	$	(46	)
Change in prices		2
		(44	)
Wholesale:
Effect of 7.6% decrease in sales volumes		(21	)
Change in prices		43
		22
Net Decrease in Non-Affiliated Generation Revenues	$	(22	)

	Increase
Source of Change in Affiliated Generation Revenues	(Decrease)
	(In millions)
Ohio Companies:
Effect of 0.6% decrease in sales volumes	$	(7	)
Change in prices		80
		73
Pennsylvania Companies:
Effect of 2.8% increase in sales volumes		10
Change in prices		(7	)
		3
Net Increase in Affiliated Generation Revenues	$	76

Expenses

Total expenses increased by $218 million in the first six months of 2008 compared with the same period of 2007. The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first six months of 2008 from the same period last year:

Source of Change in Fuel and Purchased Power	Increase  (Decrease)
	(In millions)
Fossil Fuel:
Change due to increased unit costs	$	68
Change due to volume consumed		60
		128
Nuclear Fuel:
Change due to increased unit costs		2
Change due to volume consumed		-
		2
Non-affiliated Purchased Power:
Change due to increased unit costs		120
Change due to volume purchased		(42	)
		78
Affiliated Purchased Power:
Change due to increased unit costs		7
Change due to volume purchased		(94	)
		(87	)
Net Increase in Fuel and Purchased Power Costs	$	121

Fossil fuel costs increased $128 million in the first six months of 2008 as a result of the assignment of CEI’s and TE’s leasehold interest in the Bruce Mansfield Plant to FGCO in October 2007 and higher unit prices due to increased coal transportation costs (including surcharges for increased diesel fuel prices) and emission allowance costs.

49

Purchased power costs decreased as a result of lower purchases from affiliates, partially offset by increased non-affiliated purchased power costs. Purchases from affiliated companies decreased as a result of the assignment of CEI’s and TE’s leasehold interests in the Mansfield Plant to FGCO; prior to the assignment, FGCO purchased the associated KWH from CEI and TE. Purchased power costs from non-affiliates increased primarily as a result of higher market prices in MISO and PJM partially offset by reduced volumes reflecting lower retail sales requirements.

Other operating expenses increased by $88million in the first six months of 2008 from the same period of 2007 primarily due to lease expenses relating to the assignment of CEI’s and TE’s leasehold interests in the Mansfield Plant to FGCO ($22 million) and the sale and leaseback of Mansfield Unit 1 ($48 million) completed in the second half of 2007. Higher nuclear operating costs were due to an additional refueling outage during the first six months of 2008.  Higher fossil operating costs were primarily due to additional planned maintenance outages at the Mansfield and Ashtabula Plants in 2008 and reduced gains from excess emission allowance sales.

Depreciation expense increased by $9 million in the first six months of 2008 primarily due to fossil and nuclear property additions since the second quarter of 2007.

Other Expense

Other expense increased by $6million in the first six months of 2008 from the same period of 2007 primarily as a result of an increase in nuclear decommissioning trust securities impairments and lower interest income due to reduced loans to the unregulated money pool, partially offset by lower interest expense (net of capitalized interest). Lower interest expense reflected the repayment of notes issued to associated companies in connection with the transfers of generation assets in 2005.

Legal Proceedings

See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to FES.

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 FES.

50

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of FirstEnergy Solutions Corp.:

We have reviewed the accompanying consolidated balance sheet of FirstEnergy Solutions Corp. and its subsidiaries as of June 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2008 and 2007 and the consolidated statement of cash flows for the six-month periods ended June 30, 2008 and 2007. 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 (United States), 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, 2007, and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, 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, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

August 7, 2008

51

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(In thousands)
REVENUES:
Electric sales to affiliates	$	704,283		$	690,697		$	1,480,590		$	1,404,371
Electric sales to non-affiliates		324,276			358,901			612,617			635,030
Other		42,719			19,133			77,187			47,623
Total revenues		1,071,278			1,068,731			2,170,394			2,087,024
EXPENSES:
Fuel		310,550			268,880			632,239			502,415
Purchased power from non-affiliates		220,339			162,873			427,063			349,076
Purchased power from affiliates		34,528			70,585			60,013			147,068
Other operating expenses		287,738			233,145			584,284			496,741
Provision for depreciation		56,160			48,520			105,902			96,530
General taxes		19,795			20,910			42,992			42,628
Total expenses		929,110			804,913			1,852,493			1,634,458
OPERATING INCOME		142,168			263,818			317,901			452,566
OTHER INCOME (EXPENSE):
Miscellaneous income (expense)		(2,074	)		15,369			(4,978	)		35,101
Interest expense - affiliates		(10,728	)		(22,817	)		(17,938	)		(52,263	)
Interest expense - other		(24,505	)		(21,693	)		(49,040	)		(39,051	)
Capitalized interest		10,541			4,423			17,204			7,632
Total other expense		(26,766	)		(24,718	)		(54,752	)		(48,581	)
INCOME BEFORE INCOME TAXES		115,402			239,100			263,149			403,985
INCOME TAXES		47,308			87,684			105,071			150,065
NET INCOME		68,094			151,416			158,078			253,920
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(1,821	)		(1,360	)		(3,641	)		(2,720	)
Unrealized gain (loss) on derivative hedges		(17,920	)		(13,170	)		(12,202	)		4,588
Change in unrealized gain on available-for-sale securities		(17,709	)		41,340			(69,561	)		58,790
Other comprehensive income (loss)		(37,450	)		26,810			(85,404	)		60,658
Income tax expense (benefit) related to other
comprehensive income		(13,313	)		9,226			(30,716	)		21,559
Other comprehensive income (loss), net of tax		(24,137	)		17,584			(54,688	)		39,099
TOTAL COMPREHENSIVE INCOME	$	43,957		$	169,000		$	103,390		$	293,019
The accompanying Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are an integral part of
these balance sheets.

52

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,		December 31,
	2008		2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2	$	2
Receivables-
Customers (less accumulated provisions of $7,378,000 and $8,072,000,
respectively, for uncollectible accounts)		117,858		133,846
Associated companies		473,974		376,499
Other (less accumulated provisions of $2,516,000 and $9,000,
respectively, for uncollectible accounts)		7,956		3,823
Notes receivable from associated companies		554,279		92,784
Materials and supplies, at average cost		489,544		427,015
Prepayments and other		172,409		92,340
		1,816,022		1,126,309
PROPERTY, PLANT AND EQUIPMENT:
In service		9,741,996		8,294,768
Less - Accumulated provision for depreciation		4,134,280		3,892,013
		5,607,716		4,402,755
Construction work in progress		1,221,289		761,701
		6,829,005		5,164,456
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		1,234,635		1,332,913
Long-term notes receivable from associated companies		62,900		62,900
Other		65,992		40,004
		1,363,527		1,435,817
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits		247,968		276,923
Lease assignment receivable from associated companies		67,256		215,258
Goodwill		24,248		24,248
Property taxes		47,774		47,774
Pension assets		15,417		16,723
Unamortized sale and leaseback costs		73,378		70,803
Other		28,792		43,953
		504,833		695,682
	$	10,513,387	$	8,422,264
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,938,215	$	1,441,196
Short-term borrowings-
Associated companies		1,216,707		264,064
Other		1,000,000		300,000
Accounts payable-
Associated companies		347,806		445,264
Other		214,738		177,121
Accrued taxes		72,538		171,451
Other		264,225		237,806
		5,054,229		3,036,902
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 750 shares-
7 shares outstanding		1,162,977		1,164,922
Accumulated other comprehensive income		85,966		140,654
Retained earnings		1,256,733		1,108,655
Total common stockholder's equity		2,505,676		2,414,231
Long-term debt and other long-term obligations		478,312		533,712
		2,983,988		2,947,943
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		1,043,442		1,060,119
Accumulated deferred investment tax credits		58,822		61,116
Asset retirement obligations		836,198		810,114
Retirement benefits		66,515		63,136
Property taxes		48,095		48,095
Lease market valuation liability		330,457		353,210
Other		91,641		41,629
		2,475,170		2,437,419
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	10,513,387	$	8,422,264
The accompanying Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are an integral part of
these balance sheets.

53

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30,
	2008			2007
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	158,078		$	253,920
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		105,902			96,530
Nuclear fuel and lease amortization		51,207			49,406
Deferred rents and lease market valuation liability		(52,537	)		-
Deferred income taxes and investment tax credits, net		51,961			48,026
Investment impairment		33,533			10,856
Accrued compensation and retirement benefits		(8,399	)		(2,597	)
Commodity derivative transactions, net		3,705			2,727
Gain on asset sales		(8,836	)		(12,105	)
Cash collateral, net		(5,355	)		(3,120	)
Pension trust contribution		-			(64,020	)
Decrease (increase) in operating assets:
Receivables		(86,773	)		(42,901	)
Materials and supplies		(27,867	)		14,492
Prepayments and other current assets		(14,512	)		(8,270	)
Increase (decrease) in operating liabilities:
Accounts payable		(37,794	)		(148,755	)
Accrued taxes		(98,948	)		4,452
Accrued interest		(1,603	)		387
Other		(16,743	)		12,177
Net cash provided from operating activities		45,019			211,205
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		455,735			-
Equity contribution from parent		-			700,000
Short-term borrowings, net		1,652,643			364,847
Redemptions and Repayments-
Long-term debt		(458,377	)		(745,536	)
Common stock dividend payments		(10,000	)		(37,000	)
Net cash provided from financing activities		1,640,001			282,311
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(1,152,502	)		(302,424	)
Proceeds from asset sales		10,875			12,120
Sales of investment securities held in trusts		384,692			367,924
Purchases of investment securities held in trusts		(404,502	)		(389,286	)
Loans to associated companies, net		(461,496	)		(184,176	)
Other		(62,087	)		2,326
Net cash used for investing activities		(1,685,020	)		(493,516	)
Net change in cash and cash equivalents		-			-
Cash and cash equivalents at beginning of period		2			2
Cash and cash equivalents at end of period	$	2		$	2
The accompanying Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are an
integral part of these balance sheets.

54

OHIO EDISON COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF 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. They provide generation services to those customers electing to retain OE and Penn as their power supplier. OE’s power supply requirements are provided by FES – an affiliated company. Penn purchases power from FES and third-party suppliers through a competitive RFP process.

Results of Operations

In the first six months of 2008, net income decreased to $93 million from $100 million in the same period of 2007. The decrease primarily resulted from a decrease in the deferral of new regulatory assets and lower investment income, partially offset by higher electric sales revenues and lower purchased power costs.

Revenues

Revenues increased by $40 million, or 3.3%, in the first six months of 2008 compared with the same period in 2007, primarily due to increases in retail generation revenues ($26 million) and distribution throughput revenues ($13 million).

Retail generation revenues increased primarily due to higher average prices across all customer classes, partially offset by decreased KWH sales to all sectors. The higher average prices included the 2008 fuel cost recovery rider that became effective January 16, 2008 (see Regulatory Matters). Milder weather conditions in the first six months of 2008 primarily caused the lower KWH sales (cooling degree days decreased in OE’s and Penn’s service territories by 25.5% and 21.6%, respectively, from the same period in 2007). Commercial and industrial retail generation KWH sales were also impacted by increased customer shopping in Penn’s service territory in the first six months of 2008.

Changes in retail generation sales and revenues in the first six months of 2008 from the same period in 2007 are summarized in the following tables:

Retail Generation KWH Sales	Decrease
Residential		(1.4)	%
Commercial		(2.7)	%
Industrial		(4.9)	%
Decrease in Generation Sales		(2.9)	%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	14
Commercial		3
Industrial		9
Increase in Generation Revenues	$	26

Revenues from distribution throughput increased by $13 million in the first six months of 2008 compared to the same period in 2007 due to higher average unit prices for all customer classes, partially offset by lower KWH deliveries to all sectors. The higher average prices resulted from a transmission rider increase effective July 1, 2007. The lower KWH deliveries to residential and commercial customers reflected the milder weather conditions described above.

Changes in distribution KWH deliveries and revenues in the first six months of 2008 from the same period in 2007 are summarized in the following tables.

55

Distribution KWH Deliveries	Decrease
Residential		(0.7)	%
Commercial		(0.5)	%
Industrial		(1.7)	%
Decrease in Distribution Deliveries		(1.0)	%

Distribution Revenues	Increase
	(In millions)
Residential	$	4
Commercial		5
Industrial		4
Increase in Distribution Revenues	$	13

Expenses

Total expenses increased by $23 million in the first six months of 2008 from the same period of 2007. The following table presents changes from the prior year by expense category.

Expenses – Changes	Increase (Decrease)
		(In millions)
Purchased power costs	$	(24	)
Other operating costs		(3	)
Provision for depreciation		5
Amortization of regulatory assets		5
Deferral of new regulatory assets		40
Net Increase in Expenses	$	23

Lower purchased power costs in the first six months of 2008 primarily reflected the lower retail generation KWH sales requirements. The decrease in other operating costs for the first six months of 2008 was primarily due to lower MISO transmission expenses, partially offset by increased costs associated with OE’s leasehold interests in Beaver Valley Unit 2, due to a refueling outage in the second quarter of 2008. Higher depreciation expense in the first six months of 2008 reflected capital additions subsequent to the second quarter of 2007. Higher amortization of regulatory assets in the first six months of 2008 was primarily due to increased amortization of MISO transmission deferrals. The decrease in the deferral of new regulatory assets for the first six months of 2008 was primarily due to lower MISO cost deferrals ($16 million) and lower RCP fuel deferrals ($19 million), as more transmission and generation costs were recovered from customers through PUCO-approved riders.

Other Income

Other income decreased $20 million in the first six months of 2008 as compared with the same period of 2007 primarily due to reductions in interest income on notes receivable from associated companies due to principal payments since the second quarter of 2007.

Legal Proceedings

See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections 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.

56

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 sheet of Ohio Edison Company and its subsidiaries as of June 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2008 and 2007 and the consolidated statement of cash flows for the six-month periods ended June 30, 2008 and 2007. 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 (United States), 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, 2007, and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, 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, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

August 7, 2008

57

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended							Six Months Ended
	June 30,							June 30,
		2008			2007			2008			2007
	(In thousands)
REVENUES:
Electric sales		$	583,268		$	569,430		$	1,205,539		$	1,163,774
Excise tax collections			26,287			27,351			56,665			58,605
Total revenues			609,555			596,781			1,262,204			1,222,379
EXPENSES:
Purchased power			308,049			322,639			648,235			672,491
Other operating costs			137,619			147,086			277,945			280,101
Provision for depreciation			21,414			19,110			42,907			37,958
Amortization of regulatory assets			47,856			46,126			96,394			91,543
Deferral of new regulatory assets			(25,901	)		(54,344	)		(51,312	)		(90,993	)
General taxes			44,389			45,393			94,842			95,138
Total expenses			533,426			526,010			1,109,011			1,086,238
OPERATING INCOME			76,129			70,771			153,193			136,141
OTHER INCOME (EXPENSE):
Investment income			11,488			21,346			26,543			47,976
Miscellaneous income (expense)			(285	)		2,319			(4,091	)		2,692
Interest expense			(16,901	)		(21,416	)		(34,542	)		(42,438	)
Capitalized interest			159			152			269			262
Total other income (expense)			(5,539	)		2,401			(11,821	)		8,492
INCOME BEFORE INCOME TAXES			70,590			73,172			141,372			144,633
INCOME TAXES			21,748			27,559			48,621			44,985
NET INCOME			48,842			45,613			92,751			99,648
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirment benefits			(3,994	)		(3,424	)		(7,988	)		(6,847	)
Change in unrealized gain on available-for-sale securities			(2,803	)		5,099			(10,374	)		4,973
Other comprehensive income (loss)			(6,797	)		1,675			(18,362	)		(1,874	)
Income tax expense (benefit) related to other
comprehensive income			(2,564	)		388			(6,826	)		(1,115	)
Other comprehensive income (loss), net of tax			(4,233	)		1,287			(11,536	)		(759	)
TOTAL COMPREHENSIVE INCOME		$	44,609		$	46,900		$	81,215		$	98,889
The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part
of these statements.

58

OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,		December 31,
	2008		2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	889	$	732
Receivables-
Customers (less accumulated provisions of $6,222,000 and $8,032,000,
respectively, for uncollectible accounts)		262,717		248,990
Associated companies		174,773		185,437
Other (less accumulated provisions of $30,000 and $5,639,000,
respectively, for uncollectible accounts)		10,094		12,395
Notes receivable from associated companies		472,884		595,859
Prepayments and other		15,833		10,341
		937,190		1,053,754
UTILITY PLANT:
In service		2,819,937		2,769,880
Less - Accumulated provision for depreciation		1,093,194		1,090,862
		1,726,743		1,679,018
Construction work in progress		40,065		50,061
		1,766,808		1,729,079
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies		257,940		258,870
Investment in lease obligation bonds		248,894		253,894
Nuclear plant decommissioning trusts		117,941		127,252
Other		32,205		36,037
		656,980		676,053
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		682,844		737,326
Pension assets		243,348		228,518
Property taxes		65,520		65,520
Unamortized sale and leaseback costs		42,632		45,133
Other		32,017		48,075
		1,066,361		1,124,572
	$	4,427,339	$	4,583,458
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	159,659	$	333,224
Short-term borrowings-
Associated companies		-		50,692
Other		122,874		2,609
Accounts payable-
Associated companies		112,484		174,088
Other		24,654		19,881
Accrued taxes		58,265		89,571
Accrued interest		21,126		22,378
Other		64,332		65,163
		563,394		757,606
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 175,000,000 shares -
60 shares outstanding		1,220,424		1,220,512
Accumulated other comprehensive income		36,850		48,386
Retained earnings		400,028		307,277
Total common stockholder's equity		1,657,302		1,576,175
Long-term debt and other long-term obligations		838,283		840,591
		2,495,585		2,416,766
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		779,427		781,012
Accumulated deferred investment tax credits		15,015		16,964
Asset retirement obligations		96,469		93,571
Retirement benefits		174,592		178,343
Deferred revenues - electric service programs		25,078		46,849
Other		277,779		292,347
		1,368,360		1,409,086
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	4,427,339	$	4,583,458
The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part
of these balance sheets.

59

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30,
	2008			2007
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	92,751		$	99,648
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		42,907			37,958
Amortization of regulatory assets		96,394			91,543
Deferral of new regulatory assets		(51,312	)		(90,993	)
Amortization of lease costs		(4,399	)		(4,367	)
Deferred income taxes and investment tax credits, net		7,059			3,017
Accrued compensation and retirement benefits		(31,579	)		(25,829	)
Pension trust contribution		-			(20,261	)
Decrease (increase) in operating assets-
Receivables		30,159			(60,535	)
Prepayments and other current assets		(2,485	)		(3,162	)
Increase (decrease) in operating liabilities-
Accounts payable		(56,831	)		10,080
Accrued taxes		(31,306	)		(87,969	)
Accrued interest		(1,252	)		(1,306	)
Electric service prepayment programs		(21,771	)		(19,144	)
Other		2,671			4,545
Net cash provided from (used for) operating activities		71,006			(66,775	)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		69,573			2,859
Redemptions and Repayments-
Common stock		-			(500,000	)
Long-term debt		(175,577	)		(1,181	)
Dividend Payments-
Common stock		-			(50,000	)
Net cash used for financing activities		(106,004	)		(548,322	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(92,061	)		(66,607	)
Sales of investment securities held in trusts		79,613			22,225
Purchases of investment securities held in trusts		(84,130	)		(25,878	)
Loan repayments from associated companies, net		123,905			670,774
Cash investments		5,000			-
Other		2,828			14,770
Net cash provided from investing activities		35,155			615,284
Net increase in cash and cash equivalents		157			187
Cash and cash equivalents at beginning of period		732			712
Cash and cash equivalents at end of period	$	889		$	899
The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral
part of these statements.

60

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF 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 six months of 2008 decreased to $124 million from $132 million in the same period of 2007. The decrease resulted primarily from lower revenues,  higher purchased power costs and reduced regulatory asset deferrals, partially offset by the elimination of fuel costs (due to assigning leasehold interests in generating assets to FGCO) and decreases in other operating expenses.

Revenues

Revenues decreased by $19 million, or 2%, in the first six months of 2008 compared to the same period of 2007 primarily due to a decrease in wholesale generation revenues ($61million), partially offset by an increase in retail generation revenues ($32 million) and distribution revenues ($10 million).

Wholesale generation revenues decreased due to the assignment of CEI’s leasehold interests in the Bruce Mansfield Plant to FGCO in October 2007. Prior to the assignment, CEI sold power from its interests in the plant to FGCO.

Retail generation revenues increased in the first six months of 2008 due to higher average unit prices across all customer classes, partially offset by a slight decrease in sales volume to all sectors compared to the same period of 2007. The higher average unit prices included the 2008 fuel cost recovery rider that became effective January 16, 2008 (see Regulatory Matters). Milder weather in the first six months of 2008 compared to the same period of 2007 primarily contributed to the decreased sales volume (cooling degree days decreased 17%).

Changes in retail generation sales and revenues in the first six months of 2008 compared to the same period in 2007 are summarized in the following tables:

Retail Generation KWH Sales	Decrease
Residential		(0.4	)%
Commercial		(0.7	)%
Industrial		(0.1	)%
Decrease in Retail Generation Sales		(0.3	)%

Retail Generation Revenues	Increase
	(in millions)
Residential	$	10
Commercial		7
Industrial		15
Increase in Generation Revenues	$	32

Revenues from distribution throughput increased by $10 million in the first six months of 2008 compared to the same period of 2007 primarily due higher average unit prices for all customer classes, partially offset by a slight decrease in KWH deliveries to all sectors. The higher average unit prices resulted from a transmission rider increase effective July 1, 2007. The lower KWH deliveries in the first six months of 2008 reflected the weather impacts described above.

61

Changes in distribution KWH deliveries and revenues in the first six months of 2008 compared to the same period of 2007 are summarized in the following tables.

Distribution KWH Deliveries	Decrease
Residential		(0.6	)%
Commercial		(1.3	)%
Industrial		(0.1	)%
Decrease in Distribution Deliveries		(0.5	)%

Distribution Revenues	Increase
	(In millions)
Residential	$	2
Commercial		3
Industrial		5
Increase in Distribution Revenues	$	10

Expenses

Total expenses decreased by $9 million in the first six months of 2008 compared to the same period of 2007. The following table presents the change from the prior year by expense category:

Expenses  - Changes	Increase (Decrease)
	(in millions)
Fuel costs	$	(28	)
Purchased power costs		19
Other operating costs		(30	)
Amortization of regulatory assets		8
Deferral of new regulatory assets		22
Net Decrease in Expenses	$	(9	)

The absence of fuel costs in the first six months of 2008 was due to the assignment of CEI’s leasehold interests in the Mansfield Plant to FGCO in October 2007. Prior to the assignment, CEI incurred fuel expenses and other operating costs related to its leasehold interest in the plant. Higher purchased power costs reflected higher unit prices, as provided for under the PSA with FES, partially offset by a decrease in volume due to lower KWH purchases. Other operating costs were lower primarily due to the assignment of CEI’s leasehold interests in the Mansfield plant as described above. Higher amortization of regulatory assets was primarily due to increased transition cost amortization ($7 million) under the effective interest methodology. The decrease in the deferral of new regulatory assets was primarily due to lower MISO cost deferrals ($14 million) and RCP fuel costs ($12 million), as more transmission and generation costs were recovered from customers through PUCO-approved riders.

Other Expense

Other expense increased by $11 million in the first six months of 2008 compared to the same period of 2007 primarily due to lower investment income, partially offset by a reduction in interest expense. Lower investment income is primarily the result of principal repayments since June 2007 on notes receivable from associated companies. The lower interest expense is primarily due to long-term debt redemptions ($386 million) since the second quarter of 2007.

Legal Proceedings

See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to CEI.

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 CEI.

.

62

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 sheet of The Cleveland Electric Illuminating Company and its subsidiaries as of June 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2008 and 2007 and the consolidated statement of cash flows for the six-month periods ended June 30, 2008 and 2007. 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 (United States), 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, 2007, and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, 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, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

August 7, 2008

63

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(In thousands)
REVENUES:
Electric sales	$	418,194		$	433,014		$	836,902		$	855,819
Excise tax collections		16,195			16,468			34,795			34,495
Total revenues		434,389			449,482			871,697			890,314
EXPENSES:
Fuel		-			14,332			-			27,523
Purchased power		185,611			178,669			378,855			359,326
Other operating costs		62,659			83,075			127,777			158,026
Provision for depreciation		17,744			18,713			36,820			37,181
Amortization of regulatory assets		38,525			35,047			76,781			68,176
Deferral of new regulatory assets		(26,019	)		(43,059	)		(55,267	)		(77,016	)
General taxes		32,425			34,098			72,508			72,992
Total expenses		310,945			320,875			637,474			646,208
OPERATING INCOME		123,444			128,607			234,223			244,106
OTHER INCOME (EXPENSE):
Investment income		8,394			16,324			17,582			34,011
Miscellaneous income (expense)		(739	)		3,226			(205	)		3,957
Interest expense		(30,935	)		(37,267	)		(63,455	)		(73,007	)
Capitalized interest		188			141			384			346
Total other expense		(23,092	)		(17,576	)		(45,694	)		(34,693	)
INCOME BEFORE INCOME TAXES		100,352			111,031			188,529			209,413
INCOME TAXES		33,779			42,082			64,105			76,915
NET INCOME		66,573			68,949			124,424			132,498
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(213	)		1,203			(426	)		2,405
Income tax expense (benefit) related to other comprehensive income		(390	)		357			(109	)		712
Other comprehensive income (loss), net of tax		177			846			(317	)		1,693
TOTAL COMPREHENSIVE INCOME	$	66,750		$	69,795		$	124,107		$	134,191
The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an
integral part of these statements.

64

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,			December 31,
	2008			2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	239		$	232
Receivables-
Customers (less accumulated provisions of $5,951,000 and $7,540,000		286,275			251,000
respectively, for uncollectible accounts)
Associated companies		92,179			166,587
Other		11,354			12,184
Notes receivable from associated companies		22,174			52,306
Prepayments and other		3,022			2,327
		415,243			484,636
UTILITY PLANT:
In service		2,173,276			2,256,956
Less - Accumulated provision for depreciation		836,523			872,801
		1,336,753			1,384,155
Construction work in progress		36,281			41,163
		1,373,034			1,425,318
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes		425,719			463,431
Other		10,265			10,285
		435,984			473,716
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		1,688,521			1,688,521
Regulatory assets		838,612			870,695
Pension assets		66,522			62,471
Property taxes		76,000			76,000
Other		8,888			32,987
		2,678,543			2,730,674
	$	4,902,804		$	5,114,344
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	207,296		$	207,266
Short-term borrowings-
Associated companies		308,214			531,943
Other		135,000			-
Accounts payable-
Associated companies		78,565			169,187
Other		6,993			5,295
Accrued taxes		56,337			94,991
Accrued interest		14,073			13,895
Other		34,468			34,350
		840,946			1,056,927
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 105,000,000 shares -
67,930,743 shares outstanding		873,433			873,536
Accumulated other comprehensive loss		(69,446	)		(69,129	)
Retained earnings		809,852			685,428
Total common stockholder's equity		1,613,839			1,489,835
Long-term debt and other long-term obligations		1,447,851			1,459,939
		3,061,690			2,949,774
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		712,467			725,523
Accumulated deferred investment tax credits		17,637			18,567
Retirement benefits		94,951			93,456
Deferred revenues - electric service programs		15,646			27,145
Lease assignment payable to associated companies		38,420			131,773
Other		121,047			111,179
		1,000,168			1,107,643
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	4,902,804		$	5,114,344
The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company
are an integral part of these balance sheets.

65

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30,
	2008			2007
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	124,424		$	132,498
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		36,820			37,181
Amortization of regulatory assets		76,781			68,176
Deferral of new regulatory assets		(55,267	)		(77,016	)
Deferred rents and lease market valuation liability		-			(45,858	)
Deferred income taxes and investment tax credits, net		(12,125	)		(7,103	)
Accrued compensation and retirement benefits		(4,027	)		1,594
Pension trust contribution		-			(24,800	)
Decrease (increase) in operating assets-
Receivables		73,484			156,526
Prepayments and other current assets		(689	)		163
Increase (decrease) in operating liabilities-
Accounts payable		(88,924	)		(308,551	)
Accrued taxes		(38,654	)		(40,119	)
Accrued interest		178			3,117
Electric service prepayment programs		(11,498	)		(11,129	)
Other		2,291			689
Net cash provided from (used for) operating activities		102,794			(114,632	)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			247,426
Redemptions and Repayments-
Long-term debt		(335	)		(103,397	)
Short-term borrowings, net		(100,562	)		(52,894	)
Dividend Payments-
Common stock		-			(104,000	)
Net cash used for financing activities		(100,897	)		(12,865	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(67,206	)		(64,366	)
Loan repayments from associated companies, net		30,132			2,292
Collection of principal on long-term notes receivable		-			133,341
Redemption of lessor notes		37,712			56,175
Other		(2,528	)		70
Net cash provided from (used for) investing activities		(1,890	)		127,512
Net increase in cash and cash equivalents		7			15
Cash and cash equivalents at beginning of period		232			221
Cash and cash equivalents at end of period	$	239		$	236
The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company
are an integral part of these statements.

66

THE TOLEDO EDISON COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF 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

Net income in the first six months of 2008 decreased to $38million from $48million in the same period of 2007. The decrease resulted primarily from lower electric sales revenues, higher purchased power costs and a decrease in the deferral of new regulatory assets, partially offset by lower other operating costs.

Revenues

Revenues decreased $48million, or 10%, in the first six months of 2008 compared to the same period of 2007 primarily due to lower wholesale generation revenues ($77 million), partially offset by increased retail generation revenues ($24million) and distribution revenues ($5million).

The decrease in wholesale revenues was primarily due to lower associated company sales of KWH from TE’s leasehold interests in generating plants.  Revenues from TE’s leasehold interests in Beaver Valley Unit 2 decreased by $31 million due to the unit’s 39-day refueling outage in the second quarter of 2008 and the incremental pricing impacts related to the termination of TE’s sale agreement with CEI. At the end of 2007, TE terminated its Beaver Valley Unit 2 sale agreement with CEI and is currently selling the 158 MW entitlement from its 18.26% leasehold interest in the unit to NGC. Revenues from PSA sales decreased by $48 million in the first six months of 2008 due to the assignment of TE’s leasehold interests in the Bruce Mansfield Plant to FGCO in October 2007. Prior to the assignment, TE sold power from its interests in the plant to FGCO.

Retail generation revenues increased in the first six months of 2008 due to higher average prices across all customer classes and increased KWH sales to commercial customers compared to the same period of 2007. The higher average prices included the 2008 fuel cost recovery rider that became effective January 16, 2008 (see Regulatory Matters). The decrease in sales to residential customers reflects milder weather in the first six months of 2008 (cooling degree days decreased 33.7% from the same period of 2007). The increase in sales to commercial customers was due to less customer shopping; generation services provided by alternative suppliers as a percentage of total sales delivered in TE’s franchise area decreased by three percentage points. Industrial KWH sales decreased due in part to lower sales to the automotive sector and a maintenance outage for a large industrial customer during the first six months of 2008.

Changes in retail electric generation KWH sales and revenues in the first six months of 2008 from the same period of 2007 are summarized in the following tables.

	Increase
Retail Generation KWH Sales	(Decrease)
Residential		(0.4	)%
Commercial		3.9	%
Industrial		(1.9	)%
Net Decrease in Retail Generation Sales		(0.4	)%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	5
Commercial		6
Industrial		13
Increase in Retail Generation Revenues	$	24

Revenues from distribution throughput increased by $5 million in the first six months of 2008 compared to the same period in 2007 due to higher average unit prices for all customer classes, partially offset by lower KWH deliveries to all sectors. The higher average prices resulted from a transmission rider increase effective July 1, 2007. The lower KWH deliveries to residential and commercial customers in the first six months of 2008 reflected the weather impacts described above.

67

Changes in distribution KWH deliveries and revenues in the first six months of 2008 from the same period of 2007 are summarized in the following tables.

Distribution KWH Deliveries	Decrease
Residential		(1.0	)%
Commercial		(0.3	)%
Industrial		(1.9	)%
Decrease in Distribution Deliveries		(1.2	)%

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

Expenses

Total expenses decreased $24 million in the first six months of 2008 from the same period of 2007. The following table presents changes from the prior year by expense category.

Expenses – Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	12
Other operating costs		(49	)
Provision for depreciation		(1	)
Amortization of regulatory assets		1
Deferral of new regulatory assets		13
Net Decrease in Expenses	$	(24	)

Higher purchased power costs primarily reflected higher unit prices as provided for under the PSA with FES. Other operating costs decreased primarily due to the reversal of the above-market lease liability ($15 million) associated with TE’s leasehold interest in Beaver Valley Unit 2 as a result of the termination of the CEI sale agreement described above and lower fuel costs ($18 million) and other operating costs ($19 million) due to the assignment of TE’s leasehold interests in the Mansfield Plant in October 2007. These decreases were partially offset by increased costs ($7 million) associated with TE’s leasehold interests in Beaver Valley Unit 2, due to a refueling outage in the second quarter of 2008. The change in the deferral of new regulatory assets was primarily due to lower deferred MISO transmission expenses ($5 million), RCP distribution costs ($3 million) and fuel costs ($6 million).

Other Expense

Other expense decreased $4million in the first six months of 2008 compared to the same period of 2007 primarily due to lower interest expense, partially offset by lower investment income. The lower interest expense resulted from lower money pool borrowings from associated companies in the first six months of 2008 and the redemption of long-term debt ($85 million principal amount) since the second quarter of 2007. The decrease in investment income resulted primarily from the principal repayments since the second quarter of 2007 on notes receivable from associated companies.

Legal Proceedings

See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to TE.

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 TE.

.

68

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 sheet of The Toledo Edison Company and its subsidiary as of June 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2008 and 2007 and the consolidated statement of cash flows for the six-month periods ended June 30, 2008 and 2007. 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 (United States), 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, 2007, and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, 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, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

August 7, 2008

69

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(In thousands)
REVENUES:
Electric sales	$	214,353		$	233,637		$	418,022		$	466,693
Excise tax collections		7,153			6,700			15,178			14,100
Total revenues		221,506			240,337			433,200			480,793
EXPENSES:
Purchased power		102,850			96,276			204,148			192,445
Other operating costs		50,805			74,471			96,134			145,260
Provision for depreciation		7,941			9,127			16,966			18,244
Amortization of regulatory assets		25,360			24,948			50,385			48,824
Deferral of new regulatory assets		(8,929	)		(18,247	)		(18,423	)		(31,728	)
General taxes		12,605			13,000			26,982			26,734
Total expenses		190,632			199,575			376,192			399,779
OPERATING INCOME		30,874			40,762			57,008			81,014
OTHER INCOME (EXPENSE):
Investment income		5,224			7,309			11,705			14,534
Miscellaneous expense		(1,949	)		(2,056	)		(3,463	)		(5,156	)
Interest expense		(5,578	)		(8,916	)		(11,613	)		(16,419	)
Capitalized interest		88			164			125			247
Total other expense		(2,215	)		(3,499	)		(3,246	)		(6,794	)
INCOME BEFORE INCOME TAXES		28,659			37,263			53,762			74,220
INCOME TAXES		7,352			15,392			15,440			26,489
NET INCOME		21,307			21,871			38,322			47,731
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(64	)		573			(127	)		1,146
Change in unrealized gain on available-for-sale-securities		(2,481	)		(669	)		(520	)		(290	)
Other comprehensive income (loss)		(2,545	)		(96	)		(647	)		856
Income tax expense (benefit) related to other
comprehensive income		(914	)		(43	)		(186	)		291
Other comprehensive income (loss), net of tax		(1,631	)		(53	)		(461	)		565
TOTAL COMPREHENSIVE INCOME	$	19,676		$	21,818		$	37,861		$	48,296
The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral
part of these statements.

70

THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,				December 31,
		2008			2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	22		$	22
Receivables-
Customers			1,251			449
Associated companies			13,465			88,796
Other (less accumulated provisions of $174,000 and $615,000,
respectively, for uncollectible accounts)			9,901			3,116
Notes receivable from associated companies			56,912			154,380
Prepayments and other			1,157			865
			82,708			247,628
UTILITY PLANT:
In service			852,806			931,263
Less - Accumulated provision for depreciation			397,496			420,445
			455,310			510,818
Construction work in progress			6,111			19,740
			461,421			530,558
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes			142,687			154,646
Long-term notes receivable from associated companies			37,384			37,530
Nuclear plant decommissioning trusts			68,002			66,759
Other			1,712			1,756
			249,785			260,691
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill			500,576			500,576
Regulatory assets			171,030			203,719
Pension assets			30,240			28,601
Property taxes			21,010			21,010
Other			62,686			20,496
			785,542			774,402
		$	1,579,456		$	1,813,279
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt		$	34		$	34
Accounts payable-
Associated companies			44,205			245,215
Other			4,339			4,449
Notes payable to associated companies			34,954			13,396
Accrued taxes			22,322			30,245
Lease market valuation liability			36,900			36,900
Other			15,256			22,747
			158,010			352,986
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			173,170			173,169
Accumulated other comprehensive loss			(11,067	)		(10,606	)
Retained earnings			213,940			175,618
Total common stockholder's equity			523,053			485,191
Long-term debt and other long-term obligations			303,386			303,397
			826,439			788,588
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			100,308			103,463
Accumulated deferred investment tax credits			9,753			10,180
Lease market valuation liability			291,550			310,000
Retirement benefits			65,291			63,215
Asset retirement obligations			29,225			28,366
Deferred revenues - electric service programs			6,622			12,639
Lease assignment payable to associated companies			28,835			83,485
Other			63,423			60,357
			595,007			671,705
COMMITMENTS AND CONTINGENCIES (Note 10)
		$	1,579,456		$	1,813,279
The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company
are an integral part of these balance sheets.

71

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30,
	2008			2007
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	38,322		$	47,731
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		16,966			18,244
Amortization of regulatory assets		50,385			48,824
Deferral of new regulatory assets		(18,423	)		(31,728	)
Deferred rents and lease market valuation liability		(39,045	)		(41,981	)
Deferred income taxes and investment tax credits, net		(3,113	)		(11,924	)
Accrued compensation and retirement benefits		(1,160	)		1,277
Pension trust contribution		-			(7,659	)
Decrease (increase) in operating assets-
Receivables		76,978			(21,594	)
Prepayments and other current assets		(292	)		59
Increase (decrease) in operating liabilities-
Accounts payable		(201,120	)		(56,784	)
Accrued taxes		(7,923	)		751
Electric service prepayment programs		(6,017	)		(5,334	)
Other		870			2,569
Net cash used for operating activities		(93,572	)		(57,549	)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		21,558			88,686
Redemptions and Repayments-
Long-term debt		(17	)		-
Dividend Payments-
Common stock		-			(40,000	)
Net cash provided from financing activities		21,541			48,686
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(34,388	)		(19,804	)
Loan repayments from (loans to) associated companies, net		97,479			(19,546	)
Collection of principal on long-term notes receivable		135			32,327
Redemption of lessor notes		11,959			14,846
Sales of investment securities held in trusts		21,791			32,499
Purchases of investment securities held in trusts		(23,581	)		(34,271	)
Other		(1,364	)		2,812
Net cash provided from investing activities		72,031			8,863
Net change in cash and cash equivalents		-			-
Cash and cash equivalents at beginning of period		22			22
Cash and cash equivalents at end of period	$	22		$	22
The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an
integral part of these statements.

72

JERSEY CENTRAL POWER & LIGHT COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF 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

Net income for the first six months of 2008 decreased to $77million from $88million in the same period in 2007. The decrease was primarily due to higher purchased power costs and other operating costs, partially offset by higher revenues and lower amortization of regulatory assets.

Revenues

In the first six months of 2008, revenues increased $165 million, or 11.3%, as compared with the same period of 2007. Retail and wholesale generation revenues increased by $96million and $84million, respectively, and distribution revenues decreased by $12 million in the first six months of 2008.

Retail generation revenues from all customer classes increased in the first six months of 2008 compared to the same period of 2007 due to higher unit prices resulting from the BGS auctions effective June 1, 2007, and June 1, 2008, partially offset by decreased retail generation KWH sales. The decreased sales volume was primarily caused by milder weather and customer shopping. In the first six months of 2008, heating and cooling degree days decreased 7.9% and 1.7%, respectively, as compared to the first six months of 2007. Customer shopping in the commercial and industrial customer sectors increased by 4.2 percentage points and 1.8 percentage points, respectively, in the first six months of 2008.

Wholesale generation revenues increased $84million in the first six months of 2008 due to higher market prices, partially offset by a slight decrease in sales volumes as compared to the first six months of 2007.

Changes in retail generation KWH sales and revenues by customer class in the first six months of 2008 compared to the same period of 2007 are summarized in the following tables:

Retail Generation KWH Sales	Decrease
Residential		(3.9	)%
Commercial		(6.7	)%
Industrial		(8.0	)%
Decrease in Generation Sales		(5.2	)%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	55
Commercial		36
Industrial		5
Increase in Generation Revenues	$	96

Distribution revenues decreased $12 million in the first six months of 2008 as compared to the same period of 2007 due to lower KWH deliveries, reflecting the weather impacts described above, partially offset by a slight increase in composite unit prices.

Changes in distribution KWH deliveries and revenues by customer class in the first six months of 2008 compared to the same period in 2007 are summarized in the following tables:

Distribution KWH Deliveries	Decrease
Residential		(3.9	)%
Commercial		(1.5	)%
Industrial		(0.7	)%
Decrease in Distribution Deliveries		(2.4	)%

73

Distribution Revenues	Decrease
	(In millions)
Residential	$	(9	)
Commercial		(3	)
Industrial		-
Decrease in Distribution Revenues	$	(12	)

Expenses

Total expenses increased by $181 million in the first six months of 2008 as compared to the same period of 2007. The following table presents changes from the prior year period by expense category:

Expenses  - Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	180
Other operating costs		7
Provision for depreciation		5
Amortization of regulatory assets		(11	)
Net increase in expenses	$	181

Purchased power costs increased in the first six months of 2008 primarily due to higher unit prices resulting from the BGS auctions effective June 1, 2007, and June 1, 2008, partially offset by a decrease in purchases due to the lower KWH sales discussed above. Other operating costs increased in the first six months of 2008 primarily due to higher expenses related to JCP&L’s customer assistance programs. Depreciation expense increased primarily due to an increase in depreciable property since the second quarter of 2007. Amortization of regulatory assets decreased in the first six months of 2008 primarily due to the completion in December 2007 of certain regulatory asset amortizations associated with TMI-2 and lower transition cost amortization due to the lower KWH sales discussed above.

Other Expenses

Other expenses increased by $8million in the first six months of 2008 as compared to the same period in 2007 primarily due to interest expense associated with JCP&L’s $550 million issuance of senior notes in May 2007 ($4 million) and reduced life insurance investment values ($3 million).

Sale of Investment

On April 17, 2008, JCP&L closed on the sale of its 86-MW Forked River Power Plant to Maxim Power Corp. for $20 million. In conjunction with this sale, FES entered into a 10-year tolling agreement with Maxim for the entire capacity of the plant. The sale is subject to regulatory accounting and did not have a material impact on JCP&L’s earnings in the first six months of 2008. The New Jersey Rate Counsel has appealed the NJBPU’s approval of the sale to the Appellate Division of the Superior Court of New Jersey, where it is currently pending.

Legal Proceedings

See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections 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

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 JCP&L.

74

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 sheet of Jersey Central Power & Light Company and its subsidiaries as of June 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2008 and 2007 and the consolidated statement of cash flows for the six-month periods ended June 30, 2008 and 2007. 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 (United States), 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, 2007, and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, 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, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

August 7, 2008

75

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(In thousands)
REVENUES:
Electric sales	$	823,104		$	768,190		$	1,604,537		$	1,439,097
Excise tax collections		11,639			11,845			24,434			24,681
Total revenues		834,743			780,035			1,628,971			1,463,778
EXPENSES:
Purchased power		534,177			464,505			1,030,858			851,002
Other operating costs		77,569			74,564			156,353			149,215
Provision for depreciation		23,543			21,319			46,825			41,835
Amortization of regulatory assets		86,507			93,890			178,026			189,118
General taxes		15,538			15,553			32,566			32,552
Total expenses		737,334			669,831			1,444,628			1,263,722
OPERATING INCOME		97,409			110,204			184,343			200,056
OTHER INCOME (EXPENSE):
Miscellaneous income		1,413			3,238			1,024			6,299
Interest expense		(24,840	)		(24,494	)		(49,304	)		(46,910	)
Capitalized interest		430			563			706			1,076
Total other expense		(22,997	)		(20,693	)		(47,574	)		(39,535	)
INCOME BEFORE INCOME TAXES		74,412			89,511			136,769			160,521
INCOME TAXES		31,468			39,698			59,871			72,362
NET INCOME		42,944			49,813			76,898			88,159
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(3,449	)		(2,115	)		(6,898	)		(4,230	)
Unrealized gain on derivative hedges		69			69			138			166
Other comprehensive loss		(3,380	)		(2,046	)		(6,760	)		(4,064	)
Income tax benefit related to other comprehensive loss		(1,469	)		(995	)		(2,939	)		(1,979	)
Other comprehensive loss, net of tax		(1,911	)		(1,051	)		(3,821	)		(2,085	)
TOTAL COMPREHENSIVE INCOME	$	41,033		$	48,762		$	73,077		$	86,074
The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral
part of these statements.

76

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,			December 31,
	2008			2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	232		$	94
Receivables-
Customers (less accumulated provisions of $2,815,000 and $3,691,000,
respectively, for uncollectible accounts)		380,491			321,026
Associated companies		63			21,297
Other		71,997			59,244
Notes receivable - associated companies		19,081			18,428
Prepaid taxes		138,018			1,012
Other		19,235			17,603
		629,117			438,704
UTILITY PLANT:
In service		4,270,624			4,175,125
Less - Accumulated provision for depreciation		1,543,779			1,516,997
		2,726,845			2,658,128
Construction work in progress		73,438			90,508
		2,800,283			2,748,636
OTHER PROPERTY AND INVESTMENTS:
Nuclear fuel disposal trust		180,676			176,512
Nuclear plant decommissioning trusts		165,543			175,869
Other		2,168			2,083
		348,387			354,464
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		1,403,794			1,595,662
Goodwill		1,825,716			1,826,190
Pension Assets		118,234			100,615
Other		15,022			16,307
		3,362,766			3,538,774
	$	7,140,553		$	7,080,578
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	28,287		$	27,206
Short-term borrowings-
Associated companies		294,739			130,381
Accounts payable-
Associated companies		9,953			7,541
Other		287,733			193,848
Accrued interest		9,264			9,318
Cash collateral from suppliers		66,412			583
Other		100,363			105,827
		796,751			474,704
CAPITALIZATION:
Common stockholder's equity-
Common stock, $10 par value, authorized 16,000,000 shares-
14,421,637 shares outstanding		144,216			144,216
Other paid-in capital		2,655,338			2,655,941
Accumulated other comprehensive loss		(23,702	)		(19,881	)
Retained earnings		138,486			237,588
Total common stockholder's equity		2,914,338			3,017,864
Long-term debt and other long-term obligations		1,547,529			1,560,310
		4,461,867			4,578,174
NONCURRENT LIABILITIES:
Power purchase contract loss liability		643,958			749,671
Accumulated deferred income taxes		789,475			800,214
Nuclear fuel disposal costs		194,745			192,402
Asset retirement obligations		92,401			89,669
Other		161,356			195,744
		1,881,935			2,027,700
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	7,140,553		$	7,080,578
The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are
an integral part of these balance sheets.

77

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30,
	2008			2007
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	76,898		$	88,159
Adjustments to reconcile net income to net cash from operating activities -
Provision for depreciation		46,825			41,835
Amortization of regulatory assets		178,026			189,118
Deferred purchased power and other costs		(93,040	)		(111,517	)
Deferred income taxes and investment tax credits, net		(8,656	)		(3,116	)
Accrued compensation and retirement benefits		(28,695	)		(11,467	)
Cash collateral received from (returned to) suppliers		66,040			(23,905	)
Pension trust contribution		-			(17,800	)
Decrease (increase) in operating assets-
Receivables		(79,001	)		(137,492	)
Materials and supplies		348			90
Prepaid taxes		(137,006	)		(109,058	)
Other current assets		186			2,540
Increase (decrease) in operating liabilities-
Accounts payable		96,297			(4,438	)
Accrued taxes		(1,972	)		27,515
Accrued interest		(54	)		(3,837	)
Tax collections payable		(12,493	)		(12,478	)
Other		9,599			459
Net cash provided from (used for) operating activities		113,302			(85,392	)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			550,000
Short-term borrowings, net		164,358			77,269
Redemptions and Repayments-
Long-term debt		(12,079	)		(304,579	)
Common Stock		-			(125,000	)
Dividend Payments-
Common stock		(176,000	)		(15,000	)
Net cash provided from (used for) financing activities		(23,721	)		182,690
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(98,068	)		(95,310	)
Proceeds from asset sales		20,000			-
Loan repayments from (loans to) associated companies, net		(653	)		765
Sales of investment securities held in trusts		113,970			77,941
Purchases of investment securities held in trusts		(122,324	)		(85,961	)
Other		(2,368	)		5,313
Net cash used for investing activities		(89,443	)		(97,252	)
Net increase in cash and cash equivalents		138			46
Cash and cash equivalents at beginning of period		94			41
Cash and cash equivalents at end of period	$	232		$	87
The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company
are an integral part of these statements.

78

METROPOLITAN EDISON COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF 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 decreased to $42 million in the first six months of 2008, compared to $51million in the same period of 2007. The decrease was primarily due to higher purchased power and other operating costs, partially offset by higher revenues.

Revenues

Revenues increased by $60 million, or 8.2%, in the first six months of 2008 primarily due to higher wholesale generation revenues. Wholesale revenues increased by $60million in the first six months of 2008, compared to the same period of 2007, primarily reflecting higher spot market prices for PJM market participants. Increased retail generation revenues and higher distribution throughput revenues were offset by a decrease in PJM transmission revenues.

In the first six months of 2008, retail generation revenues increased $6million primarily due to higher KWH sales to the residential and commercial customer classes and higher composite unit prices in all customer classes, partially offset by lower KWH sales to the industrial customer class.

Changes in retail generation sales and revenues in the first six months of 2008 compared to the same period of 2007 are summarized in the following tables:

	Increase
Retail Generation KWH Sales	(Decrease)
Residential		1.2	%
Commercial		3.3	%
Industrial		(1.7	)%
Net Increase in Retail Generation Sales		1.1	%

	Increase
Retail Generation Revenues	(Decrease)
	(In millions)
Residential	$	3
Commercial		4
Industrial		(1	)
Net Increase in Retail Generation Revenues	$	6

Revenues from distribution throughput increased $7 million in the first six months of 2008, compared to the same period in 2007. Higher transmission rates resulting from the annual update of Met-Ed’s TSC rider effective June 1, 2008 (see Regulatory Matters) were partially offset by decreased distribution rates. Increased KWH deliveries in the residential and commercial customer classes were partially offset by decreased KWH deliveries to industrial customers.

Changes in distribution KWH deliveries and revenues in the first six months of 2008 compared to the same period of 2007 are summarized in the following tables:

79

	Increase
Distribution KWH Deliveries	(Decrease)
Residential		1.2	%
Commercial		3.3	%
Industrial		(1.7	)%
Net Increase in Distribution Deliveries		1.1	%

Distribution Revenues	Increase
	(In millions)
Residential	$	1
Commercial		5
Industrial		1
Increase in Distribution Revenues	$	7

PJM transmission revenues decreased by $13million in the first six months of 2008 compared to the same period of 2007, primarily due to decreased PJM FTR revenue. Met-Ed defers the difference between revenue from its transmission rider and net transmission costs incurred in PJM, resulting in no material effect to current period earnings.

Operating Expenses

Total operating expenses increased by $73 million in the first six months of 2008 compared to the same period of 2007. The following table presents changes from the prior year by expense category:

Expenses – Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	60
Other operating costs		15
Provision for depreciation		1
Amortization of regulatory assets		2
Deferral of new regulatory assets		(6	)
General taxes		1
Net Increase in expenses	$	73

Purchased power costs increased by $60 million in the first six months of 2008 due to higher composite unit prices in PJM combined with increased KWH purchased to source increased generation sales. Other operating costs increased by $15 million in the first six months of 2008 primarily due to higher transmission expenses associated with increased transmission volumes combined with increased labor and contractor service expenses for storm restoration work performed during the first six months of 2008.

The deferral of new regulatory assets increased in the first six months of 2008 primarily due to increased transmission cost deferrals ($19 million) and universal service charge deferrals ($3 million), partially offset by the absence of the 2007 deferral of previously expensed decommissioning costs ($15 million) associated with the Saxton nuclear research facility (see Regulatory Matters).

Other Expense

Other expense increased $5 million in the first six months of 2008 primarily due to a decrease in interest earned on stranded regulatory assets, reflecting lower regulatory asset balances, and reduced life insurance investment values, partially offset by lower interest expense.

Legal Proceedings

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

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 Met-Ed.

80

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 sheet of Metropolitan Edison Company and its subsidiaries as of June 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2008 and 2007 and the consolidated statement of cash flows for the six-month periods ended June 30, 2008 and 2007. 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 (United States), 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, 2007, and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, 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, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

August 7, 2008

81

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(In thousands)
REVENUES:
Electric sales	$	373,821		$	344,241		$	753,429		$	696,377
Gross receipts tax collections		18,158			17,502			38,876			35,622
Total revenues		391,979			361,743			792,305			731,999
EXPENSES:
Purchased power		217,743			182,818			434,725			374,407
Other operating costs		117,028			111,105			224,045			209,123
Provision for depreciation		10,940			10,531			22,052			20,815
Amortization of regulatory assets		31,166			30,972			66,741			65,112
Deferral of new regulatory assets		(42,811	)		(31,895	)		(80,583	)		(74,621	)
General taxes		20,076			20,170			41,857			41,222
Total expenses		354,142			323,701			708,837			636,058
OPERATING INCOME		37,837			38,042			83,468			95,941
OTHER INCOME (EXPENSE):
Interest income		4,873			7,775			10,352			15,501
Miscellaneous income		789			1,498			480			2,607
Interest expense		(10,980	)		(13,424	)		(22,652	)		(25,180	)
Capitalized interest		199			388			(20	)		648
Total other expense		(5,119	)		(3,763	)		(11,840	)		(6,424	)
INCOME BEFORE INCOME TAXES		32,718			34,279			71,628			89,517
INCOME TAXES		12,921			14,809			29,596			38,408
NET INCOME		19,797			19,470			42,032			51,109
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(2,233	)		(1,453	)		(4,466	)		(2,905	)
Unrealized gain on derivative hedges		84			84			168			168
Other comprehensive loss		(2,149	)		(1,369	)		(4,298	)		(2,737	)
Income tax benefit related to other comprehensive loss		(971	)		(693	)		(1,941	)		(1,385	)
Other comprehensive loss, net of tax		(1,178	)		(676	)		(2,357	)		(1,352	)
TOTAL COMPREHENSIVE INCOME	$	18,619		$	18,794		$	39,675		$	49,757
The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral
part of these balance sheets.

82

METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,			December 31,
	2008			2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	130		$	135
Receivables-
Customers (less accumulated provisions of $3,452,000 and $4,327,000
respectively, for uncollectible accounts)		158,715			142,872
Associated companies		13,834			27,693
Other		29,520			18,909
Notes receivable from associated companies		12,179			12,574
Prepaid taxes		40,933			14,615
Other		346			1,348
		255,657			218,146
UTILITY PLANT:
In service		2,016,366			1,972,388
Less - Accumulated provision for depreciation		767,153			751,795
		1,249,213			1,220,593
Construction work in progress		42,922			30,594
		1,292,135			1,251,187
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		268,939			286,831
Other		985			1,360
		269,924			288,191
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		424,070			424,313
Regulatory assets		550,286			494,947
Pension assets		56,969			51,427
Other		30,762			36,411
		1,062,087			1,007,098
	$	2,879,803		$	2,764,622
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	28,500		$	-
Short-term borrowings-
Associated companies		107,812			185,327
Other		250,000			100,000
Accounts payable-
Associated companies		28,867			29,855
Other		75,093			66,694
Accrued taxes		1,569			16,020
Accrued interest		6,809			6,778
Other		25,334			27,393
		523,984			432,067
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 900,000 shares-
859,500 shares outstanding		1,202,879			1,203,186
Accumulated other comprehensive loss		(17,754	)		(15,397	)
Accumulated deficit		(97,125	)		(139,157	)
Total common stockholder's equity		1,088,000			1,048,632
Long-term debt and other long-term obligations		513,691			542,130
		1,601,691			1,590,762
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		465,330			438,890
Accumulated deferred investment tax credits		8,078			8,390
Nuclear fuel disposal costs		43,992			43,462
Asset retirement obligations		165,776			160,726
Retirement benefits		6,449			8,681
Other		64,503			81,644
		754,128			741,793
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	2,879,803		$	2,764,622
The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral
part of these balance sheets.

83

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30,
	2008			2007
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	42,032		$	51,109
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		22,052			20,815
Amortization of regulatory assets		66,741			65,112
Deferred costs recoverable as regulatory assets		(12,468	)		(38,540	)
Deferral of new regulatory assets		(80,583	)		(74,621	)
Deferred income taxes and investment tax credits, net		29,113			27,069
Accrued compensation and retirement benefits		(14,819	)		(11,150	)
Cash collateral		-			4,850
Pension trust contribution		-			(11,012	)
Increase in operating assets-
Receivables		(31,840	)		(64,465	)
Prepayments and other current assets		(25,316	)		(8,994	)
Increase (decrease) in operating liabilities-
Accounts payable		7,411			(62,308	)
Accrued taxes		(14,451	)		(10,788	)
Accrued interest		31			(446	)
Other		7,608			8,124
Net cash used for operating activities		(4,489	)		(105,245	)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		28,500			-
Short-term borrowings, net		72,485			214,229
Redemptions and Repayments-
Long-term debt		(28,637	)		(50,000	)
Net cash provided from financing activities		72,348			164,229
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(62,011	)		(49,852	)
Sales of investment securities held in trusts		81,538			55,603
Purchases of investment securities held in trusts		(87,193	)		(61,457	)
Loans from (to) associated companies, net		395			(3,290	)
Other		(593	)		9
Net cash used for investing activities		(67,864	)		(58,987	)
Net decrease in cash and cash equivalents		(5	)		(3	)
Cash and cash equivalents at beginning of period		135			130
Cash and cash equivalents at end of period	$	130		$	127
The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral
part of these balance sheets.

84

PENNSYLVANIA ELECTRIC COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern 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 decreased to $40 million in the first six months of 2008, compared to $51 million in the same period of 2007. The decrease was primarily due to increased purchased power costs, net amortization of regulatory assets and interest expense, partially offset by higher revenues.

Revenues

Revenues increased by $60 million, or 8.7%, in the first six months of 2008 primarily due to higher retail and wholesale generation revenues, distribution throughput revenues and PJM transmission revenues. Wholesale revenues increased $46 million in the first six months of 2008, compared to the same period of 2007, primarily reflecting higher spot market prices for PJM market participants.

In the first six months of 2008, retail generation revenues increased $6 million primarily due to higher KWH sales and composite unit prices in all customer classes.

Changes in retail generation sales and revenues in the first six months of 2008 compared to the same period of 2007 are summarized in the following tables:

Retail Generation KWH Sales	Increase
Residential		1.5	%
Commercial		1.5	%
Industrial		0.3	%
Increase in Retail Generation Sales		1.1	%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	2
Commercial		3
Industrial		1
Increase in Retail Generation Revenues	$	6

Revenues from distribution throughput increased $2 million in the first six months of 2008 compared to the same period of 2007. Increased usage in all customer classes along with an increase in transmission rates resulting from the annual update of Penelec’s TSC rider effective June 1, 2008 (see Regulatory Matters) was partially offset by a decrease in distribution rates.

Changes in distribution KWH deliveries and revenues in the first six months of 2008 compared to the same period of 2007 are summarized in the following tables:

85

Distribution KWH Deliveries	Increase
Residential		1.5	%
Commercial		1.5	%
Industrial		2.9	%
Increase in Distribution Deliveries		2.0	%

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

PJM transmission revenues increased by $6 million in the first six months of 2008 compared to the same period of 2007, primarily due to higher transmission volumes. Penelec defers the difference between revenue from its transmission rider and net transmission costs incurred in PJM, resulting in no material effect to current period earnings.

Operating Expenses

Total operating expenses increased by $70 million in the first six months of 2008 as compared with the same period of 2007. The following table presents changes from the prior year by expense category:

Expenses - Changes	Increase
	(In millions)
Purchased power costs	$	42
Other operating costs		4
Provision for depreciation		2
Amortization of regulatory assets, net		20
General taxes		2
Increase in expenses	$	70

Purchased power costs increased by $42 million, or 10.8%, in the first six months of 2008 compared to the same period of 2007 due to higher composite unit prices in PJM combined with increased KWH purchased to source increased generation sales. Other operating costs increased by $4 million in the first six months of 2008 principally due to higher expenses related to Penelec’s customer assistance programs. Depreciation expense increased primarily due to an increase in depreciable property since the second quarter of 2007.

Amortization of regulatory assets (net of deferrals) increased in the first six months of 2008 primarily due to the absence of the 2007 deferral of previously expensed decommissioning costs ($12 million) associated with the Saxton nuclear research facility (see Regulatory Matters) and decreased transmission cost deferrals ($11 million), partially offset by an increase in universal service charge deferrals ($3 million).

In the first six months of 2008, general taxes increased $2 million as compared to the same period of 2007, due to higher gross receipts taxes.

Other Expense

In the first six months of 2008, other expense increased primarily due to higher interest expense associated with Penelec’s $300 million senior note issuance in August 2007 and reduced life insurance investment values.

Legal Proceedings

See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to Penelec.

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 Penelec.

86

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 sheet of Pennsylvania Electric Company and its subsidiaries as of June 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2008 and 2007 and the consolidated statement of cash flows for the six-month periods ended June 30, 2008 and 2007. 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 (United States), 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, 2007, and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, 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, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

August 7, 2008

87

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(In thousands)
REVENUES:
Electric sales	$	335,382		$	315,745		$	711,410		$	654,971
Gross receipts tax collections		16,040			15,672			35,504			32,352
Total revenues		351,422			331,417			746,914			687,323
EXPENSES:
Purchased power		205,791			184,494			427,025			385,336
Other operating costs		50,100			58,267			121,177			117,728
Provision for depreciation		13,918			12,335			26,434			24,112
Amortization of regulatory assets, net		19,111			13,481			31,931			11,787
General taxes		18,345			18,350			40,200			38,201
Total expenses		307,265			286,927			646,767			577,164
OPERATING INCOME		44,157			44,490			100,147			110,159
OTHER INCOME (EXPENSE):
Miscellaneous income		1,058			2,135			867			3,552
Interest expense		(14,901	)		(13,072	)		(30,223	)		(24,409	)
Capitalized interest		70			285			(736	)		543
Total other expense		(13,773	)		(10,652	)		(30,092	)		(20,314	)
INCOME BEFORE INCOME TAXES		30,384			33,838			70,055			89,845
INCOME TAXES		11,987			14,375			30,266			38,638
NET INCOME		18,397			19,463			39,789			51,207
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(3,474	)		(2,825	)		(6,947	)		(5,650	)
Unrealized gain on derivative hedges		16			17			32			33
Change in unrealized gain on available-for-sale securities		(21	)		(13	)		(10	)		(16	)
Other comprehensive loss		(3,479	)		(2,821	)		(6,925	)		(5,633	)
Income tax benefit related to other comprehensive loss		(1,520	)		(1,302	)		(3,026	)		(2,600	)
Other comprehensive loss, net of tax		(1,959	)		(1,519	)		(3,899	)		(3,033	)
TOTAL COMPREHENSIVE INCOME	$	16,438		$	17,944		$	35,890		$	48,174
The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral
part of these statements.

88

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,		December 31,
	2008		2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	38	$	46
Receivables-
Customers (less accumulated provisions of $3,197,000 and $3,905,000
respectively, for uncollectible accounts)		137,431		137,455
Associated companies		12,309		22,014
Other		31,998		19,529
Notes receivable from associated companies		16,464		16,313
Prepaid gross receipts taxes		25,202		-
Other		11,245		3,077
		234,687		198,434
UTILITY PLANT:
In service		2,267,105		2,219,002
Less - Accumulated provision for depreciation		852,428		838,621
		1,414,677		1,380,381
Construction work in progress		22,457		24,251
		1,437,134		1,404,632
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		132,904		137,859
Non-utility generation trusts		115,152		112,670
Other		303		531
		248,359		251,060
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		777,616		777,904
Pension assets		72,698		66,111
Other		29,333		33,893
		879,647		877,908
	$	2,799,827	$	2,732,034
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	145,000	$	-
Short-term borrowings-
Associated companies		211,773		214,893
Other		100,000		-
Accounts payable-
Associated companies		24,434		83,359
Other		45,418		51,777
Accrued taxes		12,393		15,111
Accrued interest		13,167		13,167
Other		25,515		25,311
		577,700		403,618
CAPITALIZATION:
Common stockholder's equity-
Common stock, $20 par value, authorized 5,400,000 shares-
4,427,577 shares outstanding		88,552		88,552
Other paid-in capital		920,293		920,616
Accumulated other comprehensive income		1,047		4,946
Retained earnings		97,732		57,943
Total common stockholder's equity		1,107,624		1,072,057
Long-term debt and other long-term obligations		632,687		777,243
		1,740,311		1,849,300
NONCURRENT LIABILITIES:
Regulatory liabilities		79,304		73,559
Asset retirement obligations		84,428		81,849
Accumulated deferred income taxes		214,642		210,776
Retirement benefits		41,186		41,298
Other		62,256		71,634
		481,816		479,116
COMMITMENTS AND CONTINGENCIES (Note 10)
	$	2,799,827	$	2,732,034
The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are
an integral part of these statements.

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PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30,
	2008			2007
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	39,789		$	51,207
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		26,434			24,112
Amortization of regulatory assets, net		31,931			11,787
Deferred costs recoverable as regulatory assets		(13,288	)		(34,691	)
Deferred income taxes and investment tax credits, net		12,760			13,548
Accrued compensation and retirement benefits		(16,293	)		(12,130	)
Cash collateral		301			3,250
Pension trust contribution		-			(13,436	)
Increase in operating assets-
Receivables		(11,082	)		(39,530	)
Prepayments and other current assets		(33,370	)		(20,819	)
Increase (decrease) in operating liabilities-
Accounts payable		(64,438	)		(70,070	)
Accrued taxes		(11,804	)		(8,750	)
Accrued interest		-			181
Other		9,714			5,447
Net cash used for operating activities		(29,346	)		(89,894	)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		45,000			-
Short-term borrowings, net		96,880			166,303
Redemptions and Repayments-
Long-term debt		(45,320	)		-
Dividend Payments-
Common stock		-			(25,000	)
Net cash provided from financing activities		96,560			141,303
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(57,314	)		(43,904	)
Loan repayments from (loans to) associated companies, net		(151	)		1,285
Sales of investment securities held in trust		45,108			26,882
Purchases of investment securities held in trust		(53,537	)		(33,680	)
Other		(1,328	)		(1,996	)
Net cash used for investing activities		(67,222	)		(51,413	)
Net decrease in cash and cash equivalents		(8	)		(4	)
Cash and cash equivalents at beginning of period		46			44
Cash and cash equivalents at end of period	$	38		$	40
The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an
integral part of these statements.

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COMBINED MANAGEMENT’S DISCUSSION

AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain disclosures referenced in Management’s Narrative Analysis of Results of Operations of FES and the Companies. This information should be read in conjunction with (i) FES’ and the Companies’ respective Consolidated Financial Statements and Management’s Narrative Analysis of Results of Operations; (ii) the Combined Notes to Consolidated Financial Statements as they relate to FES and the Companies; and (iii) FES’ and the Companies’ respective 2007 Annual Reports on Form 10-K.

Regulatory Matters(Applicable to each of the Companies)

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 certain 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 $129 million as of June 30, 2008 (JCP&L - $73 million and Met-Ed - $56 million). Regulatory assets not earning a current return are expected to be recovered by 2014 for JCP&L and by 2020 for Met-Ed. The following table discloses regulatory assets by company:

	June 30,		December 31,		Increase
Regulatory Assets*	2008		2007		(Decrease)
	(In millions)
OE	$	683	$	737	$	(54	)
CEI		839		871		(32	)
TE		171		204		(33	)
JCP&L		1,404		1,596		(192	)
Met-Ed		550		495		55
ATSI		36		42		(6	)
Total	$	3,683	$	3,945	$	(262	)

* Penelec had net regulatory liabilities of approximately $79 million and $74 million as of June 30, 2008 and December 31, 2007, respectively. These net regulatory liabilities are included in Other Non-current Liabilities on the Consolidated Balance Sheets.

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Ohio (Applicable to OE, CEI and TE)

On January 4, 2006, the PUCO issued an order authorizing the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a twenty-five-year period through distribution rates. On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated a provision of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” and remanded the matter to the PUCO for further consideration. On September 10, 2007 the Ohio Companies filed an application with the PUCO that requested the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. On January 9, 2008 the PUCO approved the Ohio Companies’ proposed fuel cost rider to recover increased fuel costs to be incurred in 2008 commencing January 1, 2008 through December 31, 2008, which is expected to be approximately $194 million (OE - $96 million, CEI - $71 million and TE - $27 million). In addition, the PUCO ordered the Ohio Companies to file a separate application for an alternate recovery mechanism to collect the 2006 and 2007 deferred fuel costs. On February 8, 2008, the Ohio Companies filed an application proposing to recover $226 million (OE - $114 million, CEI - $79 million and TE - $33 million) of deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel rider. Recovery of the deferred fuel costs will now be addressed in the Ohio Companies’ comprehensive ESP filing, as described below, unless the MRO is implemented.

On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing to support a distribution rate increase of $332 million (OE - $156 million, CEI - $108 million and TE - $68 million). On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of its investigation into the distribution rate request. In its reports, the PUCO Staff recommended a distribution rate increase in the range of $161 million to $180 million (OE - $57 million to $66 million, CEI - $54 million to $61 million and TE - $50 million to $53 million), with $108 million to $127 million for distribution revenue increases and $53 million for recovery of costs deferred under prior cases. On January 3, 2008, the Ohio Companies and intervening parties filed objections to the Staff Reports and on January 10, 2008, the Ohio Companies filed supplemental testimony. Evidentiary hearings began on January 29, 2008 and continued through February 25, 2008. During the evidentiary hearings and filing of briefs, the PUCO Staff decreased their recommended revenue increase to a range of $117 million to $135 million. Additionally, in testimony submitted on February 11, 2008, the PUCO Staff adopted a position regarding interest deferred for RCP-related deferrals, line extension deferrals and transition tax deferrals that, if upheld by the PUCO, would result in the write-off of approximately $51 million (OE - $35 million, CEI - $11 million and TE - $5 million) of interest costs deferred through June 30, 2008. The Ohio Companies’ electric distribution rate request is addressed in their comprehensive ESP filing, as described below.

On May 1, 2008, Governor Strickland signed SB221, which became effective on July 31, 2008. The bill requires all utilities to file an ESP with the PUCO. A utility also may file an MRO in which it would have to prove the following objective market criteria:

·   the utility or its transmission service affiliate belongs to a FERC approved RTO, or there is comparable and nondiscriminatory access to the electric transmission grid;

·   the RTO has a market-monitor function and the ability to mitigate market power or the utility’s market conduct, or a similar market monitoring function exists with the ability to identify and monitor market conditions and conduct; and

·   a published source of information is available publicly or through subscription that identifies pricing information for traded electricity products, both on- and off-peak, scheduled for delivery two years into the future.

On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and MRO. The MRO outlines a CBP that would be implemented if the ESP is not approved by the PUCO. Under SB221, a PUCO ruling on the ESP filing is required within 150 days and an MRO decision is required within 90 days. The ESP proposes to phase in new generation rates for customers beginning in 2009 for up to a three-year period and would resolve the Ohio Companies’ collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. Major provisions of the ESP include:

·   a phase-in of new generation rates for up to a three-year period, whereby customers would receive a 10% phase-in credit; related costs (expected to approximate $430 million in 2009, $490 million in 2010 and $550 million in 2011) would be deferred for future collection over a period not to exceed 10 years;

·   a reconcilable rider to recover fuel transportation cost surcharges in excess of $30 million in 2009, $20 million in 2010 and $10 million in 2011;

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·   generation rate adjustments to recover any increase in fuel costs in 2011 over fuel costs incurred in 2010 for FES’ generation assets used to support the ESP;

·   generation rate adjustments to recover the costs of complying with new requirements for certain renewable energy resources, new taxes and new environmental laws or new interpretations of existing laws that take effect after January 1, 2008 and exceed $50 million during the plan period;

·   an RCP fuel rider to recover the 2006 and 2007 deferred fuel costs and carrying charges (described above) over a period not to exceed 25 years;

·   the resolution of outstanding issues pending in the Ohio Companies’ distribution rate case (described above), including annual electric distribution rate increases of $75 million for OE, $34.5 million for CEI and $40.5 million for TE. The new distribution rates would be effective January 1, 2009, for OE and TE and May 1, 2009 for CEI, with a commitment to maintain distribution rates through 2013. CEI also would be authorized to defer $25 million in distribution-related costs incurred from January 1, 2009, through April 30, 2009;

·   an adjustable delivery service improvement rider, effective January 1, 2009, through December 31, 2013, to ensure the Ohio Companies maintain customer standards for service and reliability;

·   the waiver of RTC charges for CEI’s customers as of January 1, 2009, which would result in CEI’s write-off of approximately $485 million of estimated unrecoverable transition costs;

·   the continued recovery of transmission costs, including MISO, ancillary services and congestion charges, through an annually adjusted transmission rider; a separate rider will be established to recover costs incurred annually between May 1st and September 30th for capacity purchases required to meet FERC, NERC, MISO and other applicable standards for planning reserve margin requirements;

·   a deferred transmission cost recovery rider effective January 1, 2009, through December 31, 2010 to recover transmission costs deferred by the Ohio Companies in 2005 and accumulated carrying charges through December 31, 2008; a deferred distribution cost recovery rider effective January 1, 2011, to recover distribution costs deferred under the RCP, CEI’s additional $25 million of cost deferrals in 2009, line extension deferrals and transition tax deferrals;

·   the deferral of annual storm damage expenses in excess of $13.9 million, certain line extension costs, as well as depreciation, property tax obligations and post in-service carrying charges on energy delivery capital investments for reliability and system efficiency placed in service after December 31, 2008. Effective January 1, 2014, a rider will be established to collect the deferred balance and associated carrying charges over a 10-year period; and

·   a commitment by the Ohio Companies to invest in aggregate at least $1 billion in capital improvements in their energy delivery systems through 2013 and fund $25 million for energy efficiency programs and $25 million for economic development and job retention programs through 2013.

The Ohio Companies’ MRO filing outlines a CBP for providing retail generation supply if the ESP is not approved and implemented. The CBP would use a “slice-of-system” approach where suppliers bid on tranches (approximately 100 MW) of the Ohio Companies’ total customer load. The Ohio Companies have requested PUCO approval of the MRO application by late October 2008, to allow for the necessary time to conduct the CBP in order for rates to be effective January 1, 2009.  The Ohio Companies included an interim pricing proposal as part of their ESP filing, if additional time is necessary for final PUCO approval of either the ESP or MRO. FES will be required to obtain FERC authorization to sell electric capacity or energy to the Ohio Companies under the ESP or MRO, unless a waiver is obtained.

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

Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. The fixed price under the agreement is expected to remain below wholesale market prices during the term of the 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 their 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.

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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. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec 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 merger savings, with the comprehensive transition 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, 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 to 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 costs. 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).

On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania 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. From June through October 2007, initial responsive and reply briefs were filed by various parties. Oral arguments are scheduled to take place in September 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the results of operations of Met-Ed and Penelec.

On May 22, 2008, the PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. Various intervenors filed complaints against Met-Ed’s and Penelec’s TSC filings.  In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing the company to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted with hearings for both companies scheduled to begin in January 2009. The TSCs include a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received approval from the PPUC of a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010.

On March 13, 2008, the PPUC approved the residential procurement process in Penn’s Joint Petition for Settlement. This RFP process calls for load-following, full-requirements contracts for default service procurement for residential customers for the period covering June 1, 2008 through May 31, 2011. The PPUC had previously approved the default service procurement processes for commercial and industrial customers. The default service procurement for small commercial customers was conducted through multiple RFPs, while the default service procurement for large commercial and industrial customers will utilize hourly pricing. Bids in the two RFPs for small commercial load were approved by the PPUC on February 22, 2008, and March 20, 2008. On March 28, 2008, Penn filed compliance tariffs with the new default service generation rates based on the approved RFP bids for small commercial customers which the PPUC then certified on April 4, 2008. Bids on the two RFPs for residential customers’ load were approved by the PPUC on April 16, 2008 and May 16, 2008. On May 20, 2008, Penn filed compliance tariffs with the new default service generation rates based on the approved RFP bids for residential customers which the PPUC certified on May 21, 2008. The new rates were effective June 1, 2008.

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On February 1, 2007, the Governor of Pennsylvania proposed an 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 and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and a three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. Neither chamber has formally considered the other’s bill. On February 12, 2008, the Pennsylvania House passed House Bill 2200 which provides for energy efficiency and demand management programs and targets as well as the installation of smart meters within ten years. As part of the 2008 state budget negotiations, the Alternative Energy Investment Act was enacted creating a $650 million alternative energy fund to increase the development and use of alternative and renewable energy, improve energy efficiency and reduce energy consumption. Other legislation has been introduced to address generation procurement, expiration of rate caps, conservation and renewable energy; however, consideration of these issues was postponed until the legislature returns to session in fall 2008. The final form of this pending legislation is uncertain. Consequently, Met-Ed and Penelec are is unable to predict what impact, if any, such legislation may have on their operations. However, Met-Ed and Penelec intend to file rate mitigation plans with the PPUC later this year.

New Jersey (Applicable to JCP&L)

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 June 30, 2008, the accumulated deferred cost balance totaled approximately $293 million.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting 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. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. 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 the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that 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 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. The NJBPU Staff circulated revised drafts of the proposal to interested stakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU accepted proposed rules for publication in the New Jersey Register on March 17, 2008. A public hearing on these proposed rules was held on April 23, 2008 and comments from interested parties were submitted by May 19, 2008.

New Jersey statutes require that the state periodically undertake a planning process, known as the 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 through the creation of a number of working groups to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. In addition, public stakeholder meetings were held in 2006, 2007 and the first half of 2008.

On April 17, 2008, a draft EMP was released for public comment. The draft EMP establishes five major goals:

·   maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020;

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·   reduce peak demand for electricity by 5,700 MW by 2020;

·   meet 22.5% of the state’s electricity needs with renewable energy by 2020;

·   develop low carbon emitting, efficient power plants and close the gap between the supply and demand for electricity; and

·   invest in innovative clean energy technologies and businesses to stimulate the industry’s growth in New Jersey.

Following the public hearings and comment period which extended into July 2008, a final EMP will be issued to be followed by appropriate legislation and regulation as necessary. At this time, JCP&L cannot predict the outcome of this process nor determine the impact, if any, such legislation or regulation may have on its operations.

FERC Matters (Applicable to FES and each of the Companies)

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or “SECA”) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, 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 by year-end 2008.  In the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order.

PJM Transmission Rate Design

On January 31, 2005, certain PJM transmission owners made 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. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design; notably AEP, which proposed to create a "postage stamp", or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order finding that the PJM transmission owners’ existing “license plate” or zonal 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, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones 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. The 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.

On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. The FERC’s orders on PJM rate design will prevent the allocation of a portion of the revenue requirement 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 the costs of future transmission to be recovered from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding Judge. The FERC’s action on the settlement agreement is pending. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. Reply briefs and briefs on exceptions are due in the merchant proceeding in July and August, respectively, with an initial decision by the Presiding Judge to follow. On February 11, 2008, AEP appealed the FERC’s April 19, 2007 and January 31, 2008 orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit.

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Post Transition Period Rate Design

The FERC had directed MISO, PJM, and the respective transmission owners to make filings on or before August 1, 2007 to reevaluate transmission rate design within MISO, and between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the vast majority of transmission owners, including FirstEnergy affiliates, which proposed to retain the existing transmission rate design. These filings were approved by the FERC on January 31, 2008. As a result of the FERC’s approval, the rates charged to FirstEnergy’s load-serving affiliates for transmission service over existing transmission facilities in MISO and PJM are unchanged. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and higher transmission facilities across the entire MISO footprint (known as the RECB methodology) be retained.

On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have the FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “Super Region” that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers. Lower voltage facilities would continue to be recovered in the local utility transmission rate zone through a license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On January 31, 2008, the FERC issued an order denying the complaint. A rehearing request by AEP is pending before the FERC.

Distribution of MISO Network Service Revenues

Effective February 1, 2008, the MISO Transmission Owners Agreement provides for a change in the method of distributing transmission revenues among the transmission owners. MISO and a majority of the MISO transmission owners filed on December 3, 2007 to change the MISO tariff to clarify, for purposes of distributing network transmission revenue to the transmission owners, that all network transmission service revenues, whether collected by MISO or directly by the transmission owner, are included in the revenue distribution calculation.  This clarification was necessary because some network transmission service revenues are collected and retained by transmission owners in states where retail choice does not exist, and their “unbundled” retail load is currently exempt from MISO network service charges. The tariff changes filed with the FERC ensure that revenues collected by transmission owners from bundled load are taken into account in the revenue distribution calculation, and that transmission owners with bundled load do not collect more than their revenue requirements. Absent the changes, transmission owners, and ultimately their customers, with unbundled load or in retail choice states, such as ATSI, would subsidize transmission owners with bundled load, who would collect their revenue requirement from bundled load, plus share in revenues collected by MISO from unbundled customers. This would result in a large revenue shortfall for ATSI, which would eventually be passed on to customers in the form of higher transmission rates as calculated pursuant to ATSI’s Attachment O formula under the MISO tariff.

Numerous parties filed in support of the tariff changes, including the public service commissions of Michigan, Ohio and Wisconsin. Ameren filed a protest on December 26, 2007, arguing that the December 3, 2007 filing violates the MISO Transmission Owners’ Agreement as well as an agreement among Ameren (Union Electric), MISO, and the Missouri Public Service Commission, which provides that Union Electric’s bundled load cannot be charged by MISO for network service. On February 1, 2008, the FERC issued an order conditionally accepting the tariff amendment subject to a minor compliance filing, which was made on March 3, 2008. This order ensures that ATSI will continue to receive transmission revenues from MISO equivalent to its transmission revenue requirement. A rehearing request by Ameren is pending before the FERC.

On February 1, 2008, MISO filed a request to continue using the existing revenue distribution methodology on an interim basis pending amendment of the MISO Transmission Owners’ Agreement. This request was accepted by the FERC on March 13, 2008. On that same day, MISO and the MISO transmission owners made a filing to amend the Transmission Owners’ Agreement to effectively continue the distribution of transmission revenues that was in effect prior to February 1, 2008. On May 12, 2008, the FERC issued an order approving this amendment.

MISO Ancillary Services Market and Balancing Area Consolidation

MISO made a filing on September 14, 2007 to establish an ASM for regulation, spinning and supplemental reserves, to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region. This filing would permit load serving entities to purchase their operating reserve requirements in a competitive market. FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas. On February 25, 2008, the FERC issued an order approving the ASM subject to certain compliance filings. Numerous parties filed requests for rehearing on March 26, 2008. On June 23, 2008, the FERC issued an order granting in part and denying in part rehearing. MISO has since notified the FERC that the start of its ASM will be delayed until September 9, 2008.

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On February 29, 2008, MISO submitted a compliance filing setting forth MISO’s Readiness Advisor ASM and Consolidated Balancing Authority Initiative Verification plan and status and Real-Time Operations ASM Reversion plan. FERC action on this compliance filing remains pending. On March 26, 2008, MISO submitted a tariff filing in compliance with the FERC’s 30-day directives in the February 25 order. Numerous parties submitted comments and protests on April 16, 2008. The FERC issued an order accepting the revisions pending further compliance on June 23, 2008. On April 25, 2008, MISO submitted a tariff filing in compliance with the FERC’s 60-day directives in the February 25 order. FERC action on this compliance filing remains pending. On May 23, 2008, MISO submitted its amended Balancing Authority Agreement. On July 21, 2008, the FERC issued an order conditionally accepting the amended Balancing Authority Agreement and requiring a further compliance filing.

Interconnection Agreement with AMP-Ohio

On May 4, 2007, AMP-Ohio filed a complaint in Franklin County, Ohio Common Pleas Court against FirstEnergy and TE seeking a declaratory judgment that the defendants may not terminate certain portions of a wholesale power Interconnection Agreement dated May 1, 1989 between AMP-Ohio and TE, nor further modify the rates and charges for power under that agreement. TE has served notice of termination of the Interconnection Agreement on AMP-Ohio to be effective December 31, 2008. AMP-Ohio claims that FirstEnergy, on behalf of TE, waived any right to terminate the Interconnection Agreement according to the terms of a June 6, 1997 merger settlement agreement with AMP-Ohio. Both the Interconnection Agreement and merger settlement agreement were approved by the FERC. On June 15, 2007, TE filed notice of removal of the case to United States District Court for the Southern District of Ohio. On July 11, 2007, TE moved to dismiss on the grounds that the FERC has exclusive jurisdiction over the subject matter of the complaint, or alternatively, primary jurisdiction over this matter. Responsive pleadings were filed by both parties and on March 31, 2008, the district court issued an order dismissing the matter for lack of subject matter jurisdiction. However, AMP-Ohio informed TE that it continues to object to cancellation of the power sales provisions of the Interconnection Agreement.

On May 29, 2008, TE filed with the FERC a proposed Notice of Cancellation effective midnight December 31, 2008, of the Interconnection Agreement with AMP-Ohio. AMP-Ohio protested this filing. TE also filed a Petition for Declaratory Order seeking a FERC ruling, in the alternative if cancellation is not accepted, of TE's right to file for an increase in rates effective January 1, 2009, for power provided to AMP-Ohio under the Interconnection Agreement. AMP-Ohio filed a pleading agreeing that TE may seek an increase in rates, but arguing that any increase is limited to the cost of generation owned by TE affiliates. TE has requested FERC action on both filings and expects the FERC to act on this request in the third quarter of 2008.

Duquesne’s Request to Withdraw from PJM

On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join MISO. In its filing, Duquesne asked the FERC to be relieved of certain capacity payment obligations to PJM for capacity auctions conducted prior to its departure from PJM, but covering service for planning periods through May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is to avoid paying future obligations created by PJM’s forward capacity market. FirstEnergy believes that Duquesne’s filing did not identify or address numerous legal, financial or operational issues that are implicated or affected directly by Duquesne’s proposal. Consequently, FirstEnergy submitted responsive filings that, while conceding Duquesne’s rights to exit PJM, contested various aspects of Duquesne’s proposal. FirstEnergy particularly focused on Duquesne’s proposal that it be allowed to exit PJM without payment of its share of existing capacity market commitments. FirstEnergy also objected to Duquesne’s failure to address the firm transmission service requirements that would be necessary for FirstEnergy to continue to use the Beaver Valley Plant to meet existing commitments in the PJM capacity markets and to serve native load. Other market participants also submitted filings contesting Duquesne’s plans.

On January 17, 2008, the FERC conditionally approved Duquesne’s request to exit PJM. Among other conditions, the FERC obligated Duquesne to pay the PJM capacity obligations through May 31, 2011. The FERC’s order took notice of the numerous transmission and other issues raised by FirstEnergy and other parties to the proceeding, but did not provide any responsive rulings or other guidance. Rather, the FERC ordered Duquesne to make a compliance filing in forty-five days detailing how Duquesne will satisfy its obligations under the PJM Transmission Owners’ Agreement. The FERC likewise directed MISO to submit detailed plans to integrate Duquesne into MISO. Finally, the FERC directed MISO and PJM to work together to resolve the substantive and procedural issues implicated by Duquesne’s transition into MISO. These issues remain unresolved. If Duquesne satisfies all of the obligations set by the FERC, its planned transition date is October 1, 2008.  On July 3, 2008, Duquesne and MISO filed a proposed plan for integrating Duquesne into MISO.  On July 24, 2008, numerous parties filed comments and protests to the proposed plan. FirstEnergy filed comments identifying numerous issues that must be addressed and resolved before Duquesne can transition to MISO. FirstEnergy continues to evaluate the impact of Duquesne’s withdrawal from PJM on its operations and financial condition; however, the full consequences cannot be determined until the FERC rules on the pending issues.

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On March 18, 2008, the PJM Power Providers Group filed a request for emergency clarification regarding whether Duquesne-zone generators (including the Beaver Valley Plant) could participate in PJM’s May 2008 auction for the 2011-2012 RPM delivery year. FirstEnergy and the other Duquesne-zone generators filed responsive pleadings. On April 18, 2008, the FERC issued its Order on Motion for Emergency Clarification, wherein the FERC ruled that although the status of the Duquesne-zone generators will change to “External Resource” upon Duquesne’s exit from PJM, these generators could contract with PJM for the transmission reservations necessary to participate in the May 2008 auction. FirstEnergy has complied with the FERC’s order by obtaining executed transmission service agreements for firm point-to-point transmission service for the 2011-2012 delivery year and, as such, FirstEnergy satisfied the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction. Notwithstanding these events, on April 30, 2008 and May 1, 2008, certain members of the PJM Power Providers Group filed further pleadings on these issues. On May 2, 2008, FirstEnergy filed a responsive pleading. Given that the FERC outlined the conditions under which FirstEnergy could bid the unit into the auction and FirstEnergy complied with the FERC’s conditions, FirstEnergy does not anticipate that the FERC will grant the relief requested in the pleadings.  Based on this expectation, FirstEnergy believes that the auction results would not be changed.

Complaint against PJM RPM Auction

On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act. Most of the parties comprising the RPM Buyers group were parties to the settlement approved by the FERC that established the RPM. In the complaint, the RPM Buyers request that the total projected payments to RPM sellers for the three auctions at issue be materially reduced. On July 11, 2008, PJM filed its answer to the complaint, in which it denied the allegation that the rates are unjust and unreasonable. Also on that date, FirstEnergy filed a motion to intervene. 

If the FERC were to rule unfavorably on this matter, the impact for the period ended June 30, 2008, would not be material to FES’ results of operations, cash flows or financial position, as FES only began collecting RPM revenues for the Beaver Valley Power Station on June 1, 2008.  However, such an unfavorable ruling by the FERC could have a material adverse impact on the revenues of the Beaver Valley Power Station in subsequent periods if these proceedings were to result in a significant loss of FES’ RPM revenues.

FES believes that the FERC is unlikely to grant the relief sought in the RPM Buyers’ complaint, since it largely deals with legal issues concerning the fundamentals of the RPM markets that are already at issue in a separate D.C. Circuit Court appellate proceeding. Nevertheless, FES is unable to predict the outcome of these proceedings or the resulting effect on FirstEnergy’s or FES’ results of operations, cash flows or financial position.

MISO Resource Adequacy Proposal

MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load serving entities such as the Ohio Companies, Penn Power, and FES. This requirement is proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for load serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for load serving entities in its state. FirstEnergy believes the proposal promotes a mechanism that will result in commitments from both load-serving entities and resources, including both generation and demand side resources, that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were filed on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, 2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC’s March 26 Order. On May 27, 2008, MISO submitted a compliance filing to address issues associated with planning reserve margins. On June 17, 2008, various parties submitted comments and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific issues that must be clarified and addressed. On June 25, 2008, MISO submitted a second compliance filing establishing the enforcement mechanism for the reserve margin requirement which establishes deficiency payments for load serving entities that do not meet the resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing. A FERC decision on this filing is expected this fall.

Organized Wholesale Power Markets

On February 21, 2008, the FERC issued a NOPR through which it proposes to adopt new rules that it states will “improve operations in organized electric markets, boost competition and bring additional benefits to consumers.” The proposed rule addresses demand response and market pricing during reserve shortages, long-term power contracting, market-monitoring policies, and responsiveness of RTOs and ISOs to stakeholders and customers. FirstEnergy does not believe that the proposed rule will have a significant impact on its operations. Comments on the NOPR were filed on April 21, 2008.

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Environmental Matters

Various federal, state and local authorities regulate FES and the Companies with regard to air and water quality and other environmental matters. The effects of compliance on FES and the Companies with regard to environmental matters could have a material adverse effect on their earnings and competitive position to the extent that they compete 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. FES estimates capital expenditures for environmental compliance of approximately $1.4 billion for the period 2008-2012.

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

Clean Air Act Compliance (Applicable to FES)

FES is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in the 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. FES 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 CAA. FES has disputed those alleged violations based on its CAA permit, the Ohio SIP and other information provided to the EPA 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. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding emission limits applicable to the common stack for Bay Shore Units 2, 3 and 4.

FES 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. NOX 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 NOX reductions at FES' facilities. The EPA's NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX 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 NOX emissions are contributing significantly to ozone levels in the eastern United States. FES believes its facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.

On April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. Subsequently, on May 8, 2007, the EPA proposed to revise the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR.   The EPA has not yet issued a final regulation. FGCO’s future cost of compliance with those regulations may be substantial and will depend on how they are ultimately implemented.

On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October 18, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy filed a motion to dismiss claims alleging a public nuisance. On April 24, 2008, the Court denied the motion to dismiss, but also ruled that monetary damages could not be recovered under the public nuisance claim.

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On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed.  Specifically, New Jersey alleges that "modifications" at Portland Units 1 and 2 occurred between 1980 and 1995 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. On March 14, 2008, Met-Ed filed a motion to dismiss the citizen suit claims against it and a stipulation in which the parties agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the United States District Court. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed.  Met-Ed is unable to predict the outcome of this matter.

On June 11, 2008, the EPA issued a Notice and Finding of Violation to MEW alleging that "modifications" at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program. MEW is seeking indemnification from Penelec, which was the co-owner (along with New York State Electric and Gas Company) and operator of the Homer City Power Station prior to its sale in 1999.  Although it remains liable for civil or criminal penalties and fines that may be assessed relating to events prior to the sale of the Homer City Power Station in 1999, the scope of Penelec’s indemnity obligation to and from MEW is disputed.  Penelec is unable to predict the outcome of this matter.

On May 16, 2008, FGCO received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an ACO modifying that request and setting forth a schedule for FGCO’s response. FGCO intends to fully comply with the ACO, but, at this time, is unable to predict the outcome of this matter.

National Ambient Air Quality Standards (Applicable to FES)

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 would have required reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2), ultimately capping SO2 emissions in affected states to just 2.5 million tons annually and NOX emissions to just 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” The court ruling also vacated the CAIR regional cap and trade programs for SO2 and NOX, which is currently not expected to, but may, materially impair the value of emissions allowances obtained for future compliance. The future cost of compliance with these regulations may be substantial and will depend on the action taken by the EPA or Congress in response to the Court’s ruling.

Mercury Emissions (Applicable to FES)

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, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the court vacated the CAMR ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA petitioned for rehearing by the entire court, which denied the petition on May 20, 2008.  The EPA must now petition for United States Supreme Court review of that ruling or take regulatory action to promulgate new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with mercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately implemented.

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. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant, FES’ only Pennsylvania coal-fired power plant, until 2015, if at all.

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

In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W.H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case, along with seven other similar cases, are referred to as the NSR 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 Sammis NSR 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 NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield 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 consent decree are currently estimated to be $1.3 billion for 2008-2012 for FGCO ($650 million of which is expected to be spent during 2008, with the largest portion of the remaining $650 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above.

Climate Change (Applicable to FES)

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 2012. The United States signed the Kyoto Protocol in 1998 but it was never submitted 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. Also, in an April 16, 2008 speech, President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition, 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.

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level.  At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the Senate Environmental and Public Works Committees have passed one such bill. 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 CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. On July 11, 2008, the EPA released an Advance Notice of Proposed Rulemaking, soliciting input from the public on the effects of climate change and the potential ramifications of regulation of CO2 under the CAA.

FES 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 FES 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 (Applicable to FES)

Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FES' plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FES' 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.

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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 United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 14, 2008, the Supreme Court of the United States granted a petition for a writ of certiorari to review one significant aspect of the Second Circuit Court’s opinion which is whether Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. FES is studying various control options and their costs and effectiveness. Depending on the results of such studies, the outcome of the Supreme Court’s review of the Second Circuit’s decision, the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

Regulation of Hazardous Waste (Applicable to FES and each of the Companies)

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 non-hazardous waste.

Under NRC regulations, FES and the Companies must ensure that adequate funds will be available to decommission their nuclear facilities. As of June 30, 2008, FES and the Companies had approximately $2.0 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, 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 (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seeks 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 may be liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of June 30, 2008, 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. Total liabilities of approximately $95 million (JCP&L - $68 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through June 30, 2008. Included in the total for JCP&L are accrued liabilities of approximately $57 million for environmental remediation of former manufactured gas plants in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

Other Legal Proceedings

Power Outages and Related Litigation (Applicable to JCP&L)

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.

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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 in July 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, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. 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, in March 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. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007.  Proceedings are continuing in the Superior Court and a case management conference with the presiding Judge was held on June 13, 2008.  At that conference, the plaintiffs stated their intent to drop their efforts to create a class-wide damage model and, instead of dismissing the class action, expressed their desire for a bifurcated trial on liability and damages.  The judge directed the plaintiffs to indicate, on or before August 22, 2008, how they intend to proceed under this scenario.  Thereafter, the judge expects to hold another pretrial conference to address plaintiffs' proposed procedure.JCP&L is defending this action but is unable to predict the outcome of this matter.  No liability has been accrued as of June 30, 2008.

Nuclear Plant Matters (Applicable to FES)

On May 14, 2007, the Office of Enforcement of the NRC issued a DFI to FENOC, following FENOC’s reply to an April 2, 2007 NRC request for information about two reports prepared by expert witnesses for an insurance arbitration (the insurance claim was subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse. The NRC indicated that this information was needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s DFI reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. FENOC submitted a supplemental response clarifying certain aspects of the DFI response to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRC’s Office of Enforcement after it completes the key commitments embodied in the NRC’s order. FENOC has conducted the employee training required by one portion of the confirmatory order and a consultant has performed follow-up reviews to ensure the effectiveness of that training.  The NRC continues to monitor FENOC’s compliance with all the commitments made in the confirmatory order.

In August 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The NRC is required by statute to provide an opportunity for members of the public to request a hearing on the application. No members of the public, however, requested a hearing on the Beaver Valley license renewal application. The NRC is expected to issue its draft supplemental Environmental Impact Statement and Safety Evaluation Report with open items in 2008. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and expects to obtain renewed licenses for the Beaver Valley Power Station in 2009. If renewed licenses are issued by the NRC, the Beaver Valley Power Station’s licenses would be extended until 2036 and 2047 for Units 1 and 2, respectively.

Other Legal Matters (Applicable to OE, JCP&L and FES)

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

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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. On July 30, 2007, plaintiffs’ counsel voluntarily withdrew their request for reconsideration of the April 5, 2007 Court order denying class certification and the Court heard oral argument on the plaintiffs’ motion to amend their complaint, which OE opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend their complaint. The plaintiffs have appealed the Court’s denial of the motion for certification as a class action and motion to amend their complaint.

On July 22, 2008 and July 23, 2008, three complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania as well as in the Beaver County Court of Common Pleas seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner,” one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints.

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. A final order identifying the individual damage amounts was issued on October 31, 2007. The award appeal process was initiated. The union filed a motion with the federal court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008. Oral arguments have been requested and are expected to take place in fall 2008. JCP&L recognized a liability for the potential $16 million award in 2005.

The union employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. The parties are continuing to bargain with the assistance of a federal mediator. FirstEnergy has a strike mitigation plan ready in the event of a strike.

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

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

SFAS 141(R) – “Business Combinations”

In December 2007, the FASB issued SFAS 141(R), which requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS 141(R) attempts to reduce the complexity of existing GAAP related to business combinations. The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FES and the Companies that close after January 1, 2009. In addition, the Standard also affects the accounting for changes in tax valuation allowances made after January 1, 2009, that were established as part of a business combination prior to the implementation of this Standard. FES and the Companies are currently evaluating the impact of adopting this Standard on their financial statements.

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SFAS 160 - “Noncontrolling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51”

In December 2007, the FASB issued SFAS 160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. The Statement is not expected to have a material impact on FES’ and the Companies’ financial statements.

SFAS 161 - “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133”

In March 2008, the FASB issued SFAS 161 that enhances the current disclosure framework for derivative instruments and hedging activities. The Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. The FASB believes that additional required disclosure of the fair values of derivative instruments and their gains and losses in a tabular format will provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features is designed to provide information on the potential effect on an entity’s liquidity from using derivatives. This Statement also requires cross-referencing within the footnotes to help users of financial statements locate important information about derivative instruments. The Statement is effective for fiscal years beginning on or after December 15, 2008. FES and the Companies are currently evaluating the impact of adopting this Standard on their financial statements.

SFAS 162 - “The Hierarchy of Generally Accepted Accounting Principles”

In May 2008, the FASB issued SFAS 162, which is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with GAAP. The FASB believes that the GAAP hierarchy should be directed to reporting entities, not the independent auditors, because reporting entities are responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP. This Statement is effective 60 days following the SEC’s approval of the PCAOB amendments to U.S. Auditing Standards Section 411, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles, which has not yet occurred. The Statement will not have an impact on FES’ and the Companies’ financial statements.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1.  ORGANIZATION AND BASIS OF PRESENTATION

FirstEnergy is a diversified energy company that holds, directly or indirectly, all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, 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, the FERC and, as applicable, the PUCO, the PPUC and the 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, 2007 for FirstEnergy, FES and the Companies. The consolidated unaudited financial statements of FirstEnergy, FES 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 prior year amounts have been reclassified to conform to the current year presentation. 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 8) 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) follow the equity method of accounting. 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.

The consolidated financial statements as of June 30, 2008 and for the three-month and six-month periods ended June 30, 2008 and 2007, have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their report (dated August 7, 2008) is included herein. The report of PricewaterhouseCoopers LLP states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited financial information because that report is not a “report” or a “part” of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Securities Act of 1933.

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 March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding common stock through an accelerated share repurchase program at an initial price of approximately $900 million. A final purchase price adjustment of $51 million was settled in cash on December 13, 2007. The following table reconciles basic and diluted earnings per share of common stock:

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	Three Months				Six Months
	Ended June 30				Ended June 30
Reconciliation of Basic and Diluted Earnings per Share	2008		2007		2008		2007
	(In millions, except per share amounts)
Net income	$	263	$	338	$	539	$	628
Average shares of common stock outstanding – Basic		304		304		304		309
Assumed exercise of dilutive stock options and awards		3		4		3		4
Average shares of common stock outstanding – Dilutive		307		308		307		313
Basic earnings per share	$	0.86	$	1.11	$	1.77	$	2.03
Diluted earnings per share	$	0.85	$	1.10	$	1.75	$	2.01

3.  DIVESTITURES AND DISCONTINUED OPERATIONS

On March 7, 2008, FirstEnergy sold certain telecommunication assets, resulting in a net after-tax gain of $19.3 million. As a result of the sale, FirstEnergy adjusted goodwill by $1 million for the former GPU companies due to the realization of tax benefits that had been reserved in purchase accounting. The sale of assets did not meet the criteria for classification as discontinued operations as of June 30, 2008.

4.  FAIR VALUE MEASURES

Effective January 1, 2008, FirstEnergy adopted SFAS 157, which provides a framework for measuring fair value under GAAP and, among other things, requires enhanced disclosures about assets and liabilities recognized at fair value. FirstEnergy also adopted SFAS 159 on January 1, 2008, which provides the option to measure certain financial assets and financial liabilities at fair value. FirstEnergy has analyzed its financial assets and financial liabilities within the scope of SFAS 159 and, as of June 30, 2008, has elected not to record eligible assets and liabilities at fair value.

As defined in SFAS 157, fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between willing market participants on the measurement date. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by SFAS 157 are as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those where transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. FirstEnergy’s Level 1 assets and liabilities primarily consist of exchange-traded derivatives and equity securities listed on active exchanges that are held in various trusts.

Level 2 – Pricing inputs are either directly or indirectly observable in the market as of the reporting date, other than quoted prices in active markets included in Level 1. FirstEnergy’s Level 2 consists primarily of investments in debt securities held in various trusts and commodity forwards. Additionally, Level 2 includes those financial instruments that are valued using models or other valuation methodologies based on assumptions that are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Instruments in this category include non-exchange-traded derivatives such as forwards and certain interest rate swaps.

Level 3 – Pricing inputs include inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. FirstEnergy develops its view of the future market price of key commodities through a combination of market observation and assessment (generally for the short term) and fundamental modeling (generally for the longer term). Key fundamental electricity model inputs are generally directly observable in the market or derived from publicly available historic and forecast data. Some key inputs reflect forecasts published by industry leading consultants who generally employ similar fundamental modeling approaches. Fundamental model inputs and results, as well as the selection of consultants, reflect the consensus of appropriate FirstEnergy management. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. FirstEnergy’s Level 3 instruments consist of NUG contracts.

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FirstEnergy utilizes market data and assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs.

The following table sets forth FirstEnergy’s financial assets and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of June 30, 2008. As required by SFAS 157, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. FirstEnergy’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	June 30, 2008
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total
	(In millions)
Assets:
Derivatives	$	7	$	110	$	-	$	117
Nuclear decommissioning trusts(1)		1,040		950		-		1,990
Other investments(2)		21		309		-		330
Total	$	1,068	$	1,369	$	-	$	2,437
Liabilities:
Derivatives	$	-	$	123	$	-	$	123
NUG contracts(3)		-		-		644		644
Total	$	-	$	123	$	644	$	767

(1)   Balance excludes $2 million of net receivables, payables and accrued income.

(2)   Excludes $312 million of the cash surrender value of life insurance contracts.

(3)   NUG contracts are completely offset by regulatory assets.

The determination of the above fair value measures takes into consideration various factors required under SFAS 157. These factors include the credit standing of the counterparties involved, the impact of credit enhancements (such as cash deposits, LOCs and priority interests) and the impact of nonperformance risk.

Exchange-traded derivative contracts, which include some futures and options, are generally based on unadjusted quoted market prices in active markets and are classified within Level 1. Forwards, options and swap contracts that are not exchange-traded are classified as Level 2 as the fair values of these items are based on ICE quotes or market transactions in the OTC markets. In addition, complex or longer term structured transactions can introduce the need for internally-developed model inputs that may not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is classified as Level 3.

Nuclear decommissioning trusts consist of equity securities listed on active exchanges classified as Level 1 and various debt securities and collective trusts classified as Level 2. Other investments represent the NUG trusts, spent nuclear fuel trusts and rabbi trust investments, which primarily consist of various debt securities and collective trusts classified as Level 2.

The following tables set forth a reconciliation of changes in the fair value of NUG contracts classified as Level 3 in the fair value hierarchy for the three and six months ended June 30, 2008:

	Three Months			Six Months
	Ended June 30, 2008			Ended June 30, 2008
	(In millions)
Balance at beginning of period	$	682		$	750
Realized and unrealized gains (losses)(1)		(30	)		(88	)
Purchases, sales, issuances and settlements, net(1)		(8	)		(18	)
Net transfers to (from) Level 3		-			-
Balance as of June 30, 2008	$	644		$	644
Change in unrealized gains (losses) relating to
instruments held as of June 30, 2008	$	(30	)	$	(88	)
(1)Changes in the fair value of NUG contracts are completely offset by regulatory assets and do not impact earnings

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Under FSP FAS 157-2, FirstEnergy has elected to defer, for one year, the election of SFAS 157 for financial assets and financial liabilities measured at fair value on a non-recurring basis. FirstEnergy is currently evaluating the impact of FAS 157 on those financial assets and financial liabilities measured at fair value on a non-recurring basis.

5.  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 FirstEnergy. 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 purchases and normal sales criteria. Derivatives that meet those criteria are accounted for at cost. The changes in the fair value of derivative instruments that do not meet the normal purchases and normal sales criteria 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 does not offset fair value for the right to reclaim collateral or the obligation to return collateral.

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 $78 million included in AOCL as of June 30, 2008, for derivative hedging activity, as compared to $75 million as of December 31, 2007, resulted from a net $15 million increase related to current hedging activity and a $12 million decrease due to net hedge losses reclassified to earnings during the six months ended June 30, 2008. Based on current estimates, approximately $28 million (after tax) of the net deferred losses on derivative instruments in AOCL as of June 30, 2008 are 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. As of June 30, 2008, FirstEnergy had interest rate swaps with an aggregate notional value of $150 million and a fair value of $(3) million.

During 2007 and the first six months of 2008, 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 issuance of variable-rate, short-term debt and fixed-rate, long-term debt securities by one or more of its subsidiaries as outstanding debt matures during 2008 and 2009. 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 and LIBOR rates between the date of hedge inception and the date of the debt issuance. During the first six months of 2008, FirstEnergy terminated swaps with a notional value of $650 million and entered into swaps with a notional value of $850 million. FirstEnergy paid $14 million related to the terminations, $5 million of which was deemed ineffective and recognized in current period earnings. FirstEnergy will recognize the remaining loss over the life of the associated future debt. As of June 30, 2008, FirstEnergy had forward swaps with an aggregate notional amount of $600 million and a fair value of $6 million.

6.  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 of $1.3 billion as of June 30, 2008 is primarily related to the future nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. 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 June 30, 2008, the fair value of the decommissioning trust assets was approximately $2.0 billion.

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The following tables analyze changes to the ARO balance during the three months and six months ended June 30, 2008 and 2007, respectively.

ARO Reconciliation	FirstEnergy			FES			OE		CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
Balance, April 1, 2008	$	1,287		$	824		$	95	$	2	$	29	$	91	$	163	$	83
Liabilities incurred		-			-			-		-		-		-		-		-
Liabilities settled		(1	)		(1	)		-		-		-		-		-		-
Accretion		21			13			1		-		-		1		3		1
Revisions in estimated cash flows		-			-			-		-		-		-		-		-
Balance, June 30, 2008	$	1,307		$	836		$	96	$	2	$	29	$	92	$	166	$	84
Balance, April 1, 2007	$	1,208		$	772		$	89	$	2	$	27	$	86	$	153	$	78
Liabilities incurred		-			-			-		-		-		-		-		-
Liabilities settled		-			-			-		-		-		-		-		-
Accretion		21			13			2		-		-		1		3		1
Revisions in estimated cash flows		(1	)		(1	)		-		-		-		-		-		-
Balance, June 30, 2007	$	1,228		$	784		$	91	$	2	$	27	$	87	$	156	$	79

ARO Reconciliation	FirstEnergy			FES			OE		CEI		TE		JCP&L		Met-Ed		Penelec
	(In millions)
Balance, January 1, 2008	$	1,267		$	810		$	94	$	2	$	28	$	90	$	161	$	82
Liabilities incurred		-			-			-		-		-		-		-		-
Liabilities settled		(1	)		(1	)		-		-		-		-		-		-
Accretion		41			27			2		-		1		2		5		2
Revisions in estimated cash flows		-			-			-		-		-		-		-		-
Balance, June 30, 2008	$	1,307		$	836		$	96	$	2	$	29	$	92	$	166	$	84
Balance, January 1, 2007	$	1,190		$	760		$	88	$	2	$	27	$	84	$	151	$	77
Liabilities incurred		-			-			-		-		-		-		-		-
Liabilities settled		-			-			-		-		-		-		-		-
Accretion		39			25			3		-		-		3		5		2
Revisions in estimated cash flows		(1	)		(1	)		-		-		-		-		-		-
Balance, June 30, 2007	$	1,228		$	784		$	91	$	2	$	27	$	87	$	156	$	79

7.  PENSION AND OTHER POSTRETIREMENT BENEFITS

FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its subsidiaries’ employees. The trusteed plans provide defined benefits based on years of service and compensation levels. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. FirstEnergy uses a December 31 measurement date for its pension and other postretirement benefit plans. The fair value of the plan assets represents the actual market value as of December 31, 2007. 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. 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 and six months ended June 30, 2008 and 2007, consisted of the following:

	Three Months						Six Months
	Ended June 30						Ended June 30
Pension Benefits	2008			2007			2008			2007
	(In millions)
Service cost	$	21		$	21		$	41		$	42
Interest cost		72			71			144			142
Expected return on plan assets		(116	)		(113	)		(231	)		(225	)
Amortization of prior service cost		3			3			5			5
Recognized net actuarial loss		1			11			3			21
Net periodic cost (credit)	$	(19	)	$	(7	)	$	(38	)	$	(15	)

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	Three Months						Six Months
	Ended June 30						Ended June 30
Other Postretirement Benefits	2008			2007			2008			2007
	(In millions)
Service cost	$	5		$	5		$	9		$	10
Interest cost		18			17			37			34
Expected return on plan assets		(13	)		(12	)		(26	)		(25	)
Amortization of prior service cost		(37	)		(37	)		(74	)		(74	)
Recognized net actuarial loss		12			11			24			23
Net periodic cost (credit)	$	(15	)	$	(16	)	$	(30	)	$	(32	)

Pension and postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. FES and 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 FES and each of the Companies for the three months and six months ended June 30, 2008 and 2007 were as follows:

	Three Months						Six Months
	Ended June 30						Ended June 30
Pension Benefit Cost (Credit)	2008			2007			2008			2007
	(In millions)
FES	$	4		$	5		$	8		$	10
OE		(7	)		(4	)		(13	)		(8	)
CEI		(1	)		-			(3	)		1
TE		(1	)		-			(1	)		-
JCP&L		(4	)		(2	)		(8	)		(4	)
Met-Ed		(3	)		(2	)		(5	)		(4	)
Penelec		(3	)		(2	)		(7	)		(5	)
Other FirstEnergy subsidiaries		(4	)		(2	)		(9	)		(5	)
	$	(19	)	$	(7	)	$	(38	)	$	(15	)

	Three Months						Six Months
	Ended June 30						Ended June 30
Other Postretirement Benefit Cost (Credit)	2008			2007			2008			2007
	(In millions)
FES	$	(2	)	$	(2	)	$	(4	)	$	(5	)
OE		(2	)		(3	)		(3	)		(5	)
CEI		1			1			1			2
TE		1			1			2			2
JCP&L		(4	)		(4	)		(8	)		(8	)
Met-Ed		(3	)		(3	)		(5	)		(5	)
Penelec		(3	)		(3	)		(6	)		(6	)
Other FirstEnergy subsidiaries		(3	)		(3	)		(7	)		(7	)
	$	(15	)	$	(16	)	$	(30	)	$	(32	)

8.  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.

Trusts

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.

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Loss Contingencies

FES and the Ohio Companies are exposed to losses under their applicable sale and leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events that render the applicable plant worthless. Net discounted lease payments would not be payable if the casualty loss payments are made. The following table shows each company’s net exposure to loss based upon the casualty value provisions mentioned above as of June 30, 2008:

	Maximum Exposure		Discounted Lease Payments, net		Net Exposure
	(in millions)
FES	$	1,339	$	1,189	$	150
OE	806		583		223
CEI	748		78		670
TE	748		413		335

In October 2007, CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO. FGCO assumed all of CEI’s and TE’s obligations arising under those leases. FGCO subsequently transferred the Unit 1 portion of these leasehold interests, as well as FGCO’s leasehold interests under its July 2007 Bruce Mansfield Unit 1 sale and leaseback transaction to a newly formed wholly-owned subsidiary in December 2007. The subsidiary assumed all of the lessee obligations associated with the assigned interests. However, CEI and TE will remain primarily liable on the 1987 leases and related agreements as to the lessors and other parties to the agreements. FGCO remains primarily liable on the 2007 leases and related agreements, and FES remains primarily liable as a guarantor under the related 2007 guarantees, as to the lessors and other parties to the respective agreements. These assignments terminate automatically upon the termination of the underlying leases.

On May 30, 2008, NGC purchased 56.8 MW of lessor equity interests in the OE 1987 sale and leaseback of the Perry Plant. On June 2, 2008, NGC purchased approximately 43.5 MW of lessor equity interests in the OE 1987 sale and leaseback of Beaver Valley Unit 2. Between June 2, 2008 and June 9, 2008, NGC purchased an additional 158.5 MW of additional lessor equity interests in the TE and CEI 1987 sale and leaseback of Beaver Valley Unit 2, which purchases were undertaken in connection with the previously disclosed exercise of the periodic purchase option provided in the TE and CEI sale and leaseback arrangements. The Ohio Companies continue to lease these MW under the respective sale and leaseback arrangements and the related lease debt remains outstanding.

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 may incur for power. FirstEnergy expects any above-market costs it incurs to be recovered from customers. Purchased power costs from these entities during the three months and six months ended June 30, 2008 and 2007 are shown in the following table:

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	Three Months				Six Months
	Ended June 30				Ended June 30
	2008		2007		2008		2007
	(In millions)
JCP&L	$	22	$	21	$	41	$	41
Met-Ed		16		12		32		27
Penelec		8		7		17		15
Total	$	46	$	40	$	90	$	83

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 June 30, 2008, $385 million of the transition bonds were 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 payable from TBC collections.

9.  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, based on the merits of the position, 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, if recognized in 2008. The majority of items that would not affect the 2008 effective tax rate would be purchase accounting adjustments to goodwill, if recognized in 2008. During the first six months of 2008 and 2007, there were no material changes to FirstEnergy’s unrecognized tax benefits. As of June 30, 2008, FirstEnergy expects that it is reasonably possible that approximately $155 million of the unrecognized benefits may be resolved within the next twelve months, of which $54 million to $134 million, if recognized, would affect FirstEnergy’s effective tax rate.  The potential decrease in the amount of unrecognized tax benefits is primarily associated with issues related to the capitalization of certain costs, capital gains and losses recognized on the disposition of assets and various other tax items.

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. The net amount of interest accrued as of June 30, 2008 was $60 million, as compared to $53 million as of December 31, 2007.

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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 2001-2007. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items are under appeal. The federal audits for the years 2004-2006 are expected to close before December 2008, but management anticipates certain items to be appealed. The IRS began auditing the year 2007 in February 2007 and the year 2008 in February 2008 under its Compliance Assurance Process experimental program. Neither audit is expected to close before December 2008. 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.

10.  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 June 30, 2008, outstanding guarantees and other assurances aggregated approximately $4.3 billion, consisting of parental guarantees - $0.9 billion, subsidiaries’ guarantees - $2.7 billion, surety bonds - $0.1 billion and LOCs - $0.6 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 the financing or refinancing by subsidiaries 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 $0.4 billion (included in the $0.9 billion discussed above) as of June 30, 2008 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 June 30, 2008, FirstEnergy's maximum exposure under these collateral provisions was $542 million.

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $74 million 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.

In July 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty.

(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. FirstEnergy estimates capital expenditures for environmental compliance of approximately $1.4 billion for the period 2008-2012.

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 the 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.

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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 CAA. FirstEnergy has disputed those alleged violations based on its CAA permit, the Ohio SIP and other information provided to the EPA 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. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding emission limits applicable to the common stack for Bay Shore Units 2, 3 and 4.

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. NOX 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 NOX reductions at FirstEnergy's facilities. The EPA's NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX 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 NOX emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.

On April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. Subsequently, on May 8, 2007, the EPA proposed to revise the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR.   The EPA has not yet issued a final regulation. FGCO’s future cost of compliance with those regulations may be substantial and will depend on how they are ultimately implemented.

On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October 18, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy filed a motion to dismiss claims alleging a public nuisance. On April 24, 2008, the Court denied the motion to dismiss, but also ruled that monetary damages could not be recovered under the public nuisance claim.

On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed.  Specifically, New Jersey alleges that "modifications" at Portland Units 1 and 2 occurred between 1980 and 1995 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. On March 14, 2008, Met-Ed filed a motion to dismiss the citizen suit claims against it and a stipulation in which the parties agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the United States District Court. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed.  Met-Ed is unable to predict the outcome of this matter.

On June 11, 2008, the EPA issued a Notice and Finding of Violation to MEW alleging that "modifications" at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program. MEW is seeking indemnification from Penelec, which was the co-owner (along with New York State Electric and Gas Company) and operator of the Homer City Power Station prior to its sale in 1999.  Although it remains liable for civil or criminal penalties and fines that may be assessed relating to events prior to the sale of the Homer City Power Station in 1999, the scope of Penelec’s indemnity obligation to and from MEW is disputed.  Penelec is unable to predict the outcome of this matter.

On May 16, 2008, FGCO received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an ACO modifying that request and setting forth a schedule for FGCO’s response. FGCO intends to fully comply with the ACO, but, at this time, is unable to predict the outcome of this matter.

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National Ambient Air Quality Standards

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 would have required reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2), ultimately capping SO2 emissions in affected states to just 2.5 million tons annually and NOX emissions to just 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” The court ruling also vacated the CAIR regional cap and trade programs for SO2 and NOX, which is currently not expected to, but may, materially impair the value of emissions allowances obtained for future compliance. The future cost of compliance with these regulations may be substantial and will depend on the action taken by the EPA or Congress in response to the Court’s ruling.

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, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the court vacated the CAMR ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA petitioned for rehearing by the entire court, which denied the petition on May 20, 2008.  The EPA must now petition for United States Supreme Court review of that ruling or take regulatory action to promulgate new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with mercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately implemented.

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. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant, FirstEnergy’s only Pennsylvania coal-fired power plant, until 2015, if at all.

W. H. Sammis Plant

In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W.H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case, along with seven other similar cases, are referred to as the NSR 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 Sammis NSR 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 NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield 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 consent decree are currently estimated to be $1.3 billion for 2008-2012 ($650 million of which is expected to be spent during 2008, with the largest portion of the remaining $650 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above.

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 2012. The United States signed the Kyoto Protocol in 1998 but it was never submitted 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. Also, in an April 16, 2008 speech, President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition, 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.

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There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level.  At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the Senate Environmental and Public Works Committees have passed one such bill. 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 CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. On July 11, 2008, the EPA released an Advance Notice of Proposed Rulemaking, soliciting input from the public on the effects of climate change and the potential ramifications of regulation of CO2 under the CAA.

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 United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 14, 2008, the Supreme Court of the United States granted a petition for a writ of certiorari to review one significant aspect of the Second Circuit Court’s opinion which is whether Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. FirstEnergy is studying various control options and their costs and effectiveness. Depending on the results of such studies, the outcome of the Supreme Court’s review of the Second Circuit’s decision, the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs 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 non-hazardous waste.

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities.  As of June 30, 2008, FirstEnergy had approximately $2.0 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, 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 (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seeks for these facilities.

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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 may be liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of June 30, 2008, 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. Total liabilities of approximately $95 million (JCP&L - $68 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through June 30, 2008. Included in the total for JCP&L are accrued liabilities of approximately $57 million for environmental remediation of former manufactured gas plants in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

(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 in July 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, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. 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, in March 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. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007.  Proceedings are continuing in the Superior Court and a case management conference with the presiding Judge was held on June 13, 2008.  At that conference, the plaintiffs stated their intent to drop their efforts to create a class-wide damage model and, instead of dismissing the class action, expressed their desire for a bifurcated trial on liability and damages.  The judge directed the plaintiffs to indicate, on or before August 22, 2008, how they intend to proceed under this scenario.  Thereafter, the judge expects to hold another pretrial conference to address plaintiffs' proposed procedure.FirstEnergy is defending this action but is unable to predict the outcome of this matter.  No liability has been accrued as of June 30, 2008.

Nuclear Plant Matters

On May 14, 2007, the Office of Enforcement of the NRC issued a DFI to FENOC, following FENOC’s reply to an April 2, 2007 NRC request for information about two reports prepared by expert witnesses for an insurance arbitration (the insurance claim was subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse. The NRC indicated that this information was needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s DFI reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. FENOC submitted a supplemental response clarifying certain aspects of the DFI response to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRC’s Office of Enforcement after it completes the key commitments embodied in the NRC’s order. FENOC has conducted the employee training required by one portion of the confirmatory order and a consultant has performed follow-up reviews to ensure the effectiveness of that training.  The NRC continues to monitor FENOC’s compliance with all the commitments made in the confirmatory order.

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In August 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The NRC is required by statute to provide an opportunity for members of the public to request a hearing on the application. No members of the public, however, requested a hearing on the Beaver Valley license renewal application. The NRC is expected to issue its draft supplemental Environmental Impact Statement and Safety Evaluation Report with open items in 2008. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and expects to obtain renewed licenses for the Beaver Valley Power Station in 2009. If renewed licenses are issued by the NRC, the Beaver Valley Power Station’s licenses would be extended until 2036 and 2047 for Units 1 and 2, respectively.

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. On July 30, 2007, plaintiffs’ counsel voluntarily withdrew their request for reconsideration of the April 5, 2007 Court order denying class certification and the Court heard oral argument on the plaintiffs’ motion to amend their complaint, which OE opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend their complaint. The plaintiffs have appealed the Court’s denial of the motion for certification as a class action and motion to amend their complaint.

On July 22, 2008 and July 23, 2008, three complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania as well as in the Beaver County Court of Common Pleas seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner,” one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints.

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. A final order identifying the individual damage amounts was issued on October 31, 2007. The award appeal process was initiated. The union filed a motion with the federal court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008. Oral arguments have been requested and are expected to take place in the fall. JCP&L recognized a liability for the potential $16 million award in 2005.

The union employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. The parties are continuing to bargain with the assistance of a federal mediator. FirstEnergy has a strike mitigation plan ready in the event of a strike.

FirstEnergy accrues legal 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. 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.

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11.  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 (the PUCO, the FERC, the NERC and the U.S. – Canada Power System Outage Task Force) regarding enhancements to regional reliability. The proposed enhancements were divided into two groups:  enhancements that were to be completed in 2004; and enhancements that were to be completed after 2004.  In 2004, FirstEnergy completed all of the enhancements that were recommended for completion in 2004. 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.

As a result of outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU performed a review of JCP&L’s service reliability. On June 9, 2004, the NJBPU approved a stipulation that addresses a third-party consultant’s recommendations on appropriate courses of action necessary to ensure system-wide reliability. The stipulation incorporates the consultant’s focused audit of, and recommendations regarding, JCP&L’s Planning and Operations and Maintenance programs and practices. On June 1, 2005, the consultant completed his work and issued his final report to the NJBPU. On July 14, 2006, JCP&L filed a comprehensive response to the consultant’s report with the NJBPU. JCP&L will complete the remaining substantive work described in the stipulation in 2008.  JCP&L continues to file compliance reports with the NJBPU reflecting JCP&L’s activities associated with implementing the stipulation.

In 2005, Congress amended the Federal Power Act to provide for federally-enforceable mandatory reliability standards. The mandatory reliability standards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on the Companies and ATSI. The NERC is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of its responsibilities to eight regional entities, including ReliabilityFirst Corporation.  All of FirstEnergy’s facilities are located within the ReliabilityFirst region. FirstEnergy actively participates in the NERC and ReliabilityFirst stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards.

FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards.  Nevertheless, it is clear that the NERC, ReliabilityFirst and the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with new or amended standards cannot be determined at this time. However, the 2005 amendments to the Federal Power Act provide that all prudent costs incurred to comply with the new reliability standards be recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties and thus have a material adverse effect on its financial condition, results of operations and cash flows.

In April 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the Midwest ISO region and found it to be in full compliance with all audited reliability standards.  Similarly, ReliabilityFirst has scheduled a compliance audit of FirstEnergy’s bulk-power system within the PJM region in October 2008. FirstEnergy currently does not expect any material adverse financial impact as a result of these audits.

(B)   OHIO

On January 4, 2006, the PUCO issued an order authorizing the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a twenty-five-year period through distribution rates. On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated a provision of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” and remanded the matter to the PUCO for further consideration. On September 10, 2007 the Ohio Companies filed an application with the PUCO that requested the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. On January 9, 2008 the PUCO approved the Ohio Companies’ proposed fuel cost rider to recover increased fuel costs to be incurred in 2008 commencing January 1, 2008 through December 31, 2008, which is expected to be approximately $194 million. In addition, the PUCO ordered the Ohio Companies to file a separate application for an alternate recovery mechanism to collect the 2006 and 2007 deferred fuel costs. On February 8, 2008, the Ohio Companies filed an application proposing to recover $226 million of deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel rider. Recovery of the deferred fuel costs will now be addressed in the Ohio Companies’ comprehensive ESP filing, as described below, unless the MRO is implemented.

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On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing to support a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of its investigation into the distribution rate request. In its reports, the PUCO Staff recommended a distribution rate increase in the range of $161 million to $180 million, with $108 million to $127 million for distribution revenue increases and $53 million for recovery of costs deferred under prior cases. On January 3, 2008, the Ohio Companies and intervening parties filed objections to the Staff Reports and on January 10, 2008, the Ohio Companies filed supplemental testimony. Evidentiary hearings began on January 29, 2008 and continued through February 25, 2008. During the evidentiary hearings and filing of briefs, the PUCO Staff decreased their recommended revenue increase to a range of $117 million to $135 million. Additionally, in testimony submitted on February 11, 2008, the PUCO Staff adopted a position regarding interest deferred for RCP-related deferrals, line extension deferrals and transition tax deferrals that, if upheld by the PUCO, would result in the write-off of approximately $51 million of interest costs deferred through June 30, 2008 ($0.10 per share of common stock). The Ohio Companies’ electric distribution rate request is addressed in their comprehensive ESP filing, as described below.

On May 1, 2008, Governor Strickland signed SB221, which became effective on July 31, 2008. The bill requires all utilities to file an ESP with the PUCO. A utility also may file an MRO in which it would have to prove the following objective market criteria:

·   the utility or its transmission service affiliate belongs to a FERC approved RTO, or there is comparable and nondiscriminatory access to the electric transmission grid;

·   the RTO has a market-monitor function and the ability to mitigate market power or the utility’s market conduct, or a similar market monitoring function exists with the ability to identify and monitor market conditions and conduct; and

·   a published source of information is available publicly or through subscription that identifies pricing information for traded electricity products, both on- and off-peak, scheduled for delivery two years into the future.

On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and MRO. The MRO outlines a CBP that would be implemented if the ESP is not approved by the PUCO. Under SB221, a PUCO ruling on the ESP filing is required within 150 days and an MRO decision is required within 90 days. The ESP proposes to phase in new generation rates for customers beginning in 2009 for up to a three-year period and would resolve the Ohio Companies’ collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. Major provisions of the ESP include:

·   a phase-in of new generation rates for up to a three-year period, whereby customers would receive a 10% phase-in credit; related costs (expected to approximate $430 million in 2009, $490 million in 2010 and $550 million in 2011) would be deferred for future collection over a period not to exceed 10 years;

·   a reconcilable rider to recover fuel transportation cost surcharges in excess of $30 million in 2009, $20 million in 2010 and $10 million in 2011;

·   generation rate adjustments to recover any increase in fuel costs in 2011 over fuel costs incurred in 2010 for FES’ generation assets used to support the ESP;

·   generation rate adjustments to recover the costs of complying with new requirements for certain renewable energy resources, new taxes and new environmental laws or new interpretations of existing laws that take effect after January 1, 2008 and exceed $50 million during the plan period;

·   an RCP fuel rider to recover the 2006 and 2007 deferred fuel costs and carrying charges (described above) over a period not to exceed 25 years;

·   the resolution of outstanding issues pending in the Ohio Companies’ distribution rate case (described above), including annual electric distribution rate increases of $75 million for OE, $34.5 million for CEI and $40.5 million for TE. The new distribution rates would be effective January 1, 2009, for OE and TE and May 1, 2009 for CEI, with a commitment to maintain distribution rates through 2013. CEI also would be authorized to defer $25 million in distribution-related costs incurred from January 1, 2009, through April 30, 2009;

·   an adjustable delivery service improvement rider, effective January 1, 2009, through December 31, 2013, to ensure the Ohio Companies maintain customer standards for service and reliability;

·   the waiver of RTC charges for CEI’s customers as of January 1, 2009, which would result in CEI’s write-off of approximately $485 million of estimated unrecoverable transition costs ($1.01 per share of common stock);

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·   the continued recovery of transmission costs, including MISO, ancillary services and congestion charges, through an annually adjusted transmission rider; a separate rider will be established to recover costs incurred annually between May 1st and September 30th for capacity purchases required to meet FERC, NERC, MISO and other applicable standards for planning reserve margin requirements;

·   a deferred transmission cost recovery rider effective January 1, 2009, through December 31, 2010 to recover transmission costs deferred by the Ohio Companies in 2005 and accumulated carrying charges through December 31, 2008; a deferred distribution cost recovery rider effective January 1, 2011, to recover distribution costs deferred under the RCP, CEI’s additional $25 million of cost deferrals in 2009, line extension deferrals and transition tax deferrals;

·   the deferral of annual storm damage expenses in excess of $13.9 million, certain line extension costs, as well as depreciation, property tax obligations and post in-service carrying charges on energy delivery capital investments for reliability and system efficiency placed in service after December 31, 2008. Effective January 1, 2014, a rider will be established to collect the deferred balance and associated carrying charges over a 10-year period; and

·   a commitment by the Ohio Companies to invest in aggregate at least $1 billion in capital improvements in their energy delivery systems through 2013 and fund $25 million for energy efficiency programs and $25 million for economic development and job retention programs through 2013.

The Ohio Companies’ MRO filing outlines a CBP for providing retail generation supply if the ESP is not approved and implemented. The CBP would use a “slice-of-system” approach where suppliers bid on tranches (approximately 100 MW) of the Ohio Companies’ total customer load. The Ohio Companies have requested PUCO approval of the MRO application by late October 2008, to allow for the necessary time to conduct the CBP in order for rates to be effective January 1, 2009.  The Ohio Companies included an interim pricing proposal as part of their ESP filing, if additional time is necessary for final PUCO approval of either the ESP or MRO. FES will be required to obtain FERC authorization to sell electric capacity or energy to the Ohio Companies under the ESP or MRO, unless a waiver is obtained.

(C)   PENNSYLVANIA

Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. The fixed price under the agreement is expected to remain below wholesale market prices during the term of the 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 their 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. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec 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 merger savings, with the comprehensive transition 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, 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 to 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 costs. 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).

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On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania 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. From June through October 2007, initial responsive and reply briefs were filed by various parties. Oral arguments are scheduled to take place in September 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the results of operations of Met-Ed, Penelec and FirstEnergy.

On May 22, 2008, the PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. Various intervenors filed complaints against Met-Ed’s and Penelec’s TSC filings.  In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing the company to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted with hearings for both companies scheduled to begin in January 2009. The TSCs include a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received approval from the PPUC of a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010.

On March 13, 2008, the PPUC approved the residential procurement process in Penn’s Joint Petition for Settlement. This RFP process calls for load-following, full-requirements contracts for default service procurement for residential customers for the period covering June 1, 2008 through May 31, 2011. The PPUC had previously approved the default service procurement processes for commercial and industrial customers. The default service procurement for small commercial customers was conducted through multiple RFPs, while the default service procurement for large commercial and industrial customers will utilize hourly pricing. Bids in the two RFPs for small commercial load were approved by the PPUC on February 22, 2008, and March 20, 2008. On March 28, 2008, Penn filed compliance tariffs with the new default service generation rates based on the approved RFP bids for small commercial customers which the PPUC then certified on April 4, 2008. Bids on the two RFPs for residential customers’ load were approved by the PPUC on April 16, 2008 and May 16, 2008. On May 20, 2008, Penn filed compliance tariffs with the new default service generation rates based on the approved RFP bids for residential customers which the PPUC certified on May 21, 2008. The new rates were effective June 1, 2008.

On February 1, 2007, the Governor of Pennsylvania proposed an 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 and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and a three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. Neither chamber has formally considered the other’s bill. On February 12, 2008, the Pennsylvania House passed House Bill 2200 which provides for energy efficiency and demand management programs and targets as well as the installation of smart meters within ten years. As part of the 2008 state budget negotiations, the Alternative Energy Investment Act was enacted creating a $650 million alternative energy fund to increase the development and use of alternative and renewable energy, improve energy efficiency and reduce energy consumption. Other legislation has been introduced to address generation procurement, expiration of rate caps, conservation and renewable energy; however, consideration of these issues was postponed until the legislature returns to session in fall 2008. The final form of this pending legislation is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations. However, Met-Ed and Penelec intend to file rate mitigation plans with the PPUC later this year.

(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 June 30, 2008, the accumulated deferred cost balance totaled approximately $293 million.

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In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting 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. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. 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 the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that 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. The NJBPU Staff circulated revised drafts of the proposal to interested stakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU accepted proposed rules for publication in the New Jersey Register on March 17, 2008. A public hearing on these proposed rules was held on April 23, 2008 and comments from interested parties were submitted by May 19, 2008.

New Jersey statutes require that the state periodically undertake a planning process, known as the 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 through the creation of a number of working groups to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. In addition, public stakeholder meetings were held in 2006, 2007 and the first half of 2008.

On April 17, 2008, a draft EMP was released for public comment. The draft EMP establishes five major goals:

·   maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020;

·   reduce peak demand for electricity by 5,700 MW by 2020;

·   meet 22.5% of the state’s electricity needs with renewable energy by 2020;

·   develop low carbon emitting, efficient power plants and close the gap between the supply and demand for electricity; and

·   invest in innovative clean energy technologies and businesses to stimulate the industry’s growth in New Jersey.

Following the public hearings and comment period which extended into July 2008, a final EMP will be issued to be followed by appropriate legislation and regulation as necessary. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation or regulation may have on its operations or those of JCP&L.

(E)    FERC MATTERS

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or “SECA”) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, 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 by year-end 2008.  In the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order.

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PJM Transmission Rate Design

On January 31, 2005, certain PJM transmission owners made 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. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design; notably AEP, which proposed to create a "postage stamp", or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order finding that the PJM transmission owners’ existing “license plate” or zonal 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, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones 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. The 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.

On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. The FERC’s orders on PJM rate design will prevent the allocation of a portion of the revenue requirement 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 the costs of future transmission to be recovered from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding Judge. The FERC’s action on the settlement agreement is pending. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. Reply briefs and briefs on exceptions are due in the merchant proceeding in July and August, respectively, with an initial decision by the Presiding Judge to follow. On February 11, 2008, AEP appealed the FERC’s April 19, 2007 and January 31, 2008 orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit.

Post Transition Period Rate Design

The FERC had directed MISO, PJM, and the respective transmission owners to make filings on or before August 1, 2007 to reevaluate transmission rate design within MISO, and between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the vast majority of transmission owners, including FirstEnergy affiliates, which proposed to retain the existing transmission rate design. These filings were approved by the FERC on January 31, 2008. As a result of the FERC’s approval, the rates charged to FirstEnergy’s load-serving affiliates for transmission service over existing transmission facilities in MISO and PJM are unchanged. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and higher transmission facilities across the entire MISO footprint (known as the RECB methodology) be retained.

On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have the FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “Super Region” that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers. Lower voltage facilities would continue to be recovered in the local utility transmission rate zone through a license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On January 31, 2008, the FERC issued an order denying the complaint. A rehearing request by AEP is pending before the FERC.

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Distribution of MISO Network Service Revenues

Effective February 1, 2008, the MISO Transmission Owners Agreement provides for a change in the method of distributing transmission revenues among the transmission owners. MISO and a majority of the MISO transmission owners filed on December 3, 2007 to change the MISO tariff to clarify, for purposes of distributing network transmission revenue to the transmission owners, that all network transmission service revenues, whether collected by MISO or directly by the transmission owner, are included in the revenue distribution calculation.  This clarification was necessary because some network transmission service revenues are collected and retained by transmission owners in states where retail choice does not exist, and their “unbundled” retail load is currently exempt from MISO network service charges. The tariff changes filed with the FERC ensure that revenues collected by transmission owners from bundled load are taken into account in the revenue distribution calculation, and that transmission owners with bundled load do not collect more than their revenue requirements. Absent the changes, transmission owners, and ultimately their customers, with unbundled load or in retail choice states, such as ATSI, would subsidize transmission owners with bundled load, who would collect their revenue requirement from bundled load, plus share in revenues collected by MISO from unbundled customers. This would result in a large revenue shortfall for ATSI, which would eventually be passed on to customers in the form of higher transmission rates as calculated pursuant to ATSI’s Attachment O formula under the MISO tariff.

Numerous parties filed in support of the tariff changes, including the public service commissions of Michigan, Ohio and Wisconsin. Ameren filed a protest on December 26, 2007, arguing that the December 3, 2007 filing violates the MISO Transmission Owners’ Agreement as well as an agreement among Ameren (Union Electric), MISO, and the Missouri Public Service Commission, which provides that Union Electric’s bundled load cannot be charged by MISO for network service. On February 1, 2008, the FERC issued an order conditionally accepting the tariff amendment subject to a minor compliance filing, which was made on March 3, 2008. This order ensures that ATSI will continue to receive transmission revenues from MISO equivalent to its transmission revenue requirement. A rehearing request by Ameren is pending before the FERC.

On February 1, 2008, MISO filed a request to continue using the existing revenue distribution methodology on an interim basis pending amendment of the MISO Transmission Owners’ Agreement. This request was accepted by the FERC on March 13, 2008. On that same day, MISO and the MISO transmission owners made a filing to amend the Transmission Owners’ Agreement to effectively continue the distribution of transmission revenues that was in effect prior to February 1, 2008. On May 12, 2008, the FERC issued an order approving this amendment.

MISO Ancillary Services Market and Balancing Area Consolidation

MISO made a filing on September 14, 2007 to establish an ASM for regulation, spinning and supplemental reserves, to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region. This filing would permit load serving entities to purchase their operating reserve requirements in a competitive market. FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas. On February 25, 2008, the FERC issued an order approving the ASM subject to certain compliance filings. Numerous parties filed requests for rehearing on March 26, 2008. On June 23, 2008, the FERC issued an order granting in part and denying in part rehearing. MISO has since notified the FERC that the start of its ASM will be delayed until September 9, 2008.

On February 29, 2008, MISO submitted a compliance filing setting forth MISO’s Readiness Advisor ASM and Consolidated Balancing Authority Initiative Verification plan and status and Real-Time Operations ASM Reversion plan. FERC action on this compliance filing remains pending. On March 26, 2008, MISO submitted a tariff filing in compliance with the FERC’s 30-day directives in the February 25 order. Numerous parties submitted comments and protests on April 16, 2008. The FERC issued an order accepting the revisions pending further compliance on June 23, 2008. On April 25, 2008, MISO submitted a tariff filing in compliance with the FERC’s 60-day directives in the February 25 order. FERC action on this compliance filing remains pending. On May 23, 2008, MISO submitted its amended Balancing Authority Agreement. On July 21, 2008, the FERC issued an order conditionally accepting the amended Balancing Authority Agreement and requiring a further compliance filing.

Interconnection Agreement with AMP-Ohio

On May 4, 2007, AMP-Ohio filed a complaint in Franklin County, Ohio Common Pleas Court against FirstEnergy and TE seeking a declaratory judgment that the defendants may not terminate certain portions of a wholesale power Interconnection Agreement dated May 1, 1989 between AMP-Ohio and TE, nor further modify the rates and charges for power under that agreement. TE has served notice of termination of the Interconnection Agreement on AMP-Ohio to be effective December 31, 2008. AMP-Ohio claims that FirstEnergy, on behalf of TE, waived any right to terminate the Interconnection Agreement according to the terms of a June 6, 1997 merger settlement agreement with AMP-Ohio. Both the Interconnection Agreement and merger settlement agreement were approved by the FERC. On June 15, 2007, TE filed notice of removal of the case to United States District Court for the Southern District of Ohio. On July 11, 2007, TE moved to dismiss on the grounds that the FERC has exclusive jurisdiction over the subject matter of the complaint, or alternatively, primary jurisdiction over this matter. Responsive pleadings were filed by both parties and on March 31, 2008, the district court issued an order dismissing the matter for lack of subject matter jurisdiction. However, AMP-Ohio informed TE that it continues to object to cancellation of the power sales provisions of the Interconnection Agreement.

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On May 29, 2008, TE filed with the FERC a proposed Notice of Cancellation effective midnight December 31, 2008, of the Interconnection Agreement with AMP-Ohio. AMP-Ohio protested this filing. TE also filed a Petition for Declaratory Order seeking a FERC ruling, in the alternative if cancellation is not accepted, of TE's right to file for an increase in rates effective January 1, 2009, for power provided to AMP-Ohio under the Interconnection Agreement. AMP-Ohio filed a pleading agreeing that TE may seek an increase in rates, but arguing that any increase is limited to the cost of generation owned by TE affiliates. TE has requested FERC action on both filings and expects the FERC to act on this request in the third quarter of 2008.

Duquesne’s Request to Withdraw from PJM

On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join MISO. In its filing, Duquesne asked the FERC to be relieved of certain capacity payment obligations to PJM for capacity auctions conducted prior to its departure from PJM, but covering service for planning periods through May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is to avoid paying future obligations created by PJM’s forward capacity market. FirstEnergy believes that Duquesne’s filing did not identify or address numerous legal, financial or operational issues that are implicated or affected directly by Duquesne’s proposal. Consequently, FirstEnergy submitted responsive filings that, while conceding Duquesne’s rights to exit PJM, contested various aspects of Duquesne’s proposal. FirstEnergy particularly focused on Duquesne’s proposal that it be allowed to exit PJM without payment of its share of existing capacity market commitments. FirstEnergy also objected to Duquesne’s failure to address the firm transmission service requirements that would be necessary for FirstEnergy to continue to use the Beaver Valley Plant to meet existing commitments in the PJM capacity markets and to serve native load. Other market participants also submitted filings contesting Duquesne’s plans.

On January 17, 2008, the FERC conditionally approved Duquesne’s request to exit PJM. Among other conditions, the FERC obligated Duquesne to pay the PJM capacity obligations through May 31, 2011. The FERC’s order took notice of the numerous transmission and other issues raised by FirstEnergy and other parties to the proceeding, but did not provide any responsive rulings or other guidance. Rather, the FERC ordered Duquesne to make a compliance filing in forty-five days detailing how Duquesne will satisfy its obligations under the PJM Transmission Owners’ Agreement. The FERC likewise directed MISO to submit detailed plans to integrate Duquesne into MISO. Finally, the FERC directed MISO and PJM to work together to resolve the substantive and procedural issues implicated by Duquesne’s transition into MISO. These issues remain unresolved. If Duquesne satisfies all of the obligations set by the FERC, its planned transition date is October 1, 2008.  On July 3, 2008, Duquesne and MISO filed a proposed plan for integrating Duquesne into MISO.  On July 24, 2008, numerous parties filed comments and protests to the proposed plan. FirstEnergy filed comments identifying numerous issues that must be addressed and resolved before Duquesne can transition to MISO. FirstEnergy continues to evaluate the impact of Duquesne’s withdrawal from PJM on its operations and financial condition; however, the full consequences cannot be determined until the FERC rules on the pending issues.

On March 18, 2008, the PJM Power Providers Group filed a request for emergency clarification regarding whether Duquesne-zone generators (including the Beaver Valley Plant) could participate in PJM’s May 2008 auction for the 2011-2012 RPM delivery year. FirstEnergy and the other Duquesne-zone generators filed responsive pleadings. On April 18, 2008, the FERC issued its Order on Motion for Emergency Clarification, wherein the FERC ruled that although the status of the Duquesne-zone generators will change to “External Resource” upon Duquesne’s exit from PJM, these generators could contract with PJM for the transmission reservations necessary to participate in the May 2008 auction. FirstEnergy has complied with the FERC’s order by obtaining executed transmission service agreements for firm point-to-point transmission service for the 2011-2012 delivery year and, as such, FirstEnergy satisfied the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction. Notwithstanding these events, on April 30, 2008 and May 1, 2008, certain members of the PJM Power Providers Group filed further pleadings on these issues. On May 2, 2008, FirstEnergy filed a responsive pleading. Given that the FERC outlined the conditions under which FirstEnergy could bid the unit into the auction and FirstEnergy complied with the FERC’s conditions, FirstEnergy does not anticipate that the FERC will grant the relief requested in the pleadings.  Based on this expectation, FirstEnergy believes that the auction results would not be changed.

Complaint against PJM RPM Auction

On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act. Most of the parties comprising the RPM Buyers group were parties to the settlement approved by the FERC that established the RPM. In the complaint, the RPM Buyers request that the total projected payments to RPM sellers for the three auctions at issue be materially reduced. On July 11, 2008, PJM filed its answer to the complaint, in which it denied the allegation that the rates are unjust and unreasonable. Also on that date, FirstEnergy filed a motion to intervene. 

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If the FERC were to rule unfavorably on this matter, the impact for the period ended June 30, 2008, would not be material to FirstEnergy’s results of operations, cash flows or financial position, as FES only began collecting RPM revenues for the Beaver Valley Power Station on June 1, 2008. However, such an unfavorable ruling by the FERC could have a material adverse impact on the revenues of the Beaver Valley Power Station in subsequent periods if these proceedings were to result in a significant loss of FES’ RPM revenues.

FES believes that the FERC is unlikely to grant the relief sought in the RPM Buyers’ complaint, since it largely deals with legal issues concerning the fundamentals of the RPM markets that are already at issue in a separate D.C. Circuit Court appellate proceeding. Nevertheless, FES is unable to predict the outcome of these proceedings or the resulting effect on FirstEnergy’s or FES’ results of operations, cash flows or financial position.

MISO Resource Adequacy Proposal

MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load serving entities such as the Ohio Companies, Penn Power, and FES. This requirement is proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for load serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for load serving entities in its state. FirstEnergy believes the proposal promotes a mechanism that will result in commitments from both load-serving entities and resources, including both generation and demand side resources, that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were filed on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, 2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC’s March 26 Order. On May 27, 2008, MISO submitted a compliance filing to address issues associated with planning reserve margins. On June 17, 2008, various parties submitted comments and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific issues that must be clarified and addressed. On June 25, 2008, MISO submitted a second compliance filing establishing the enforcement mechanism for the reserve margin requirement which establishes deficiency payments for load serving entities that do not meet the resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing. A FERC decision on this filing is expected this fall.

Organized Wholesale Power Markets

On February 21, 2008, the FERC issued a NOPR through which it proposes to adopt new rules that it states will “improve operations in organized electric markets, boost competition and bring additional benefits to consumers.” The proposed rule addresses demand response and market pricing during reserve shortages, long-term power contracting, market-monitoring policies, and responsiveness of RTOs and ISOs to stakeholders and customers. FirstEnergy does not believe that the proposed rule will have a significant impact on its operations. Comments on the NOPR were filed on April 21, 2008.

12.  NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

SFAS 141(R) – “Business Combinations”

In December 2007, the FASB issued SFAS 141(R), which: (i) requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; (ii) establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and (iii) requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FirstEnergy that close after January 1, 2009. In addition, the Standard also affects the accounting for changes in tax valuation allowances made after January 1, 2009, that were established as part of a business combination prior to the implementation of this Standard. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial statements.

SFAS 160 - “Non-controlling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51”

In December 2007, the FASB issued SFAS 160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. The Statement is not expected to have a material impact on FirstEnergy’s financial statements.

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SFAS 161 - “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133”

In March 2008, the FASB issued SFAS 161 that enhances the current disclosure framework for derivative instruments and hedging activities. The Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. The FASB believes that additional required disclosure of the fair values of derivative instruments and their gains and losses in a tabular format will provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features is designed to provide information on the potential effect on an entity’s liquidity from using derivatives. This Statement also requires cross-referencing within the footnotes to help users of financial statements locate important information about derivative instruments. The Statement is effective for fiscal years beginning on or after December 15, 2008. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial statements.

SFAS 162 - “The Hierarchy of Generally Accepted Accounting Principles”

In May 2008, the FASB issued SFAS 162, which is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with GAAP. The FASB believes that the GAAP hierarchy should be directed to reporting entities, not the independent auditors, because reporting entities are responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP. This Statement is effective 60 days following the SEC’s approval of the PCAOB amendments to U.S. Auditing Standards Section 411, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles, which has not yet occurred. The Statement will not have an impact on FirstEnergy’s financial statements.

13.  SEGMENT INFORMATION

FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio transitional generation services. The “Other” segment primarily consists of telecommunications services. 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 default service 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 from 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 electricity sales primarily in Ohio, Pennsylvania, Maryland and Michigan, owns or leases 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 PSA 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 PSA 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 the purchase of electricity from the competitive energy services segment through full-requirements PSA arrangements, the deferral and amortization of certain fuel costs authorized for recovery by the energy delivery services segment and the net MISO transmission revenues and expenses related to the delivery of generation load. This segment’s total assets consist of accounts receivable for generation revenues from retail customers.

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Segment Financial Information
						Ohio
	Energy		Competitive			Transitional
	Delivery		Energy			Generation						Reconciling
Three Months Ended	Services		Services			Services			Other			Adjustments			Consolidated
	(In millions)
June 30, 2008
External revenues	$	2,182	$	375		$	683		$	20		$	(15	)	$	3,245
Internal revenues		-		704			-			-			(704	)		-
Total revenues		2,182		1,079			683			20			(719	)		3,245
Depreciation and amortization		241		59			11			1			4			316
Investment income		40		(8	)		(1	)		6			(21	)		16
Net interest charges		99		28			-			-			48			175
Income taxes		129		45			13			(1	)		(26	)		160
Net income		193		66			19			26			(41	)		263
Total assets		23,423		9,240			266			281			335			33,545
Total goodwill		5,582		24			-			-			-			5,606
Property additions		196		683			-			9			18			906
June 30, 2007
External revenues	$	2,095	$	398		$	625		$	9		$	(18	)	$	3,109
Internal revenues		-		691			-			-			(691	)		-
Total revenues		2,095		1,089			625			9			(709	)		3,109
Depreciation and amortization		249		51			(49	)		1			5			257
Investment income		62		5			-			-			(37	)		30
Net interest charges		116		42			-			1			39			198
Income taxes		141		96			19			(3	)		(31	)		222
Net income		207		142			30			6			(47	)		338
Total assets		23,602		7,284			260			236			651			32,033
Total goodwill		5,874		24			-			-			-			5,898
Property additions		245		139			-			2			15			401
Six Months Ended
June 30, 2008
External revenues	$	4,394	$	704		$	1,390		$	60		$	(26	)	$	6,522
Internal revenues		-		1,480			-			-			(1,480	)		-
Total revenues		4,394		2,184			1,390			60			(1,506	)		6,522
Depreciation and amortization		496		112			15			1			9			633
Investment income		85		(14	)		-			6			(44	)		33
Net interest charges		202		55			-			-			89			346
Income taxes		248		103			28			13			(45	)		347
Net income		372		153			42			48			(76	)		539
Total assets		23,423		9,240			266			281			335			33,545
Total goodwill		5,582		24			-			-			-			5,606
Property additions		451		1,145			-			21			-			1,617
June 30, 2007
External revenues	$	4,135	$	719		$	1,245		$	20		$	(37	)	$	6,082
Internal revenues		-		1,404			-			-			(1,404	)		-
Total revenues		4,135		2,123			1,245			20			(1,441	)		6,082
Depreciation and amortization		469		102			(64	)		2			11			520
Investment income		132		8			1			-			(78	)		63
Net interest charges		223		92			1			2			60			378
Income taxes		289		160			35			2			(64	)		422
Net income		425		240			53			7			(97	)		628
Total assets		23,602		7,284			260			236			651			32,033
Total goodwill		5,874		24			-			-			-			5,898
Property additions		400		263			-			3			31			697

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 and elimination of intersegment transactions.

131

14. SUPPLEMENTAL GUARANTOR INFORMATION

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty. This transaction is classified as an operating lease under GAAP for FES and FirstEnergy and a financing for FGCO.

The consolidating statements of income for the three-month and six-month periods ended June 30, 2008 and 2007, consolidating balance sheets as of June 30, 2008 and December 31, 2007 and condensed consolidating statements of cash flows for the six-months ended June 30, 2008 and 2007 for FES (parent and guarantor), FGCO and NGC (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FGCO and NGC are, therefore, reflected in FES’ investment accounts and earnings as if operating lease treatment was achieved. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.

132

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
For the Three Months Ended June 30, 2008	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
REVENUES	$	1,064,627		$	565,225		$	287,028		$	(845,602	)	$	1,071,278
EXPENSES:
Fuel		3,605			277,192			29,753			-			310,550
Purchased power from non-affiliates		220,339			-			-			-			220,339
Purchased power from affiliates		842,670			2,932			34,528			(845,602	)		34,528
Other operating expenses		29,842			124,173			121,534			12,189			287,738
Provision for depreciation		1,600			30,027			25,893			(1,360	)		56,160
General taxes		4,727			11,504			3,564			-			19,795
Total expenses		1,102,783			445,828			215,272			(834,773	)		929,110
OPERATING INCOME (LOSS)		(38,156	)		119,397			71,756			(10,829	)		142,168
OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		98,590			489			(9,449	)		(91,704	)		(2,074	)
Interest expense - affiliates		(50	)		(7,920	)		(2,758	)		-			(10,728	)
Interest expense - other		(6,663	)		(23,697	)		(10,632	)		16,487			(24,505	)
Capitalized interest		28			9,856			657			-			10,541
Total other income (expense)		91,905			(21,272	)		(22,182	)		(75,217	)		(26,766	)
INCOME BEFORE INCOME TAXES		53,749			98,125			49,574			(86,046	)		115,402
INCOME TAXES (BENEFIT)		(14,345	)		38,467			20,838			2,348			47,308
NET INCOME	$	68,094		$	59,658		$	28,736		$	(88,394	)	$	68,094

133

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
For the Three Months Ended June 30, 2007	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
REVENUES	$	1,074,858		$	453,553		$	279,092		$	(738,772	)	$	1,068,731
EXPENSES:
Fuel		7,513			235,653			25,714			-			268,880
Purchased power from non-affiliates		162,873			-			-			-			162,873
Purchased power from affiliates		731,260			57,291			20,806			(738,772	)		70,585
Other operating expenses		30,519			65,694			136,932			-			233,145
Provision for depreciation		469			25,239			22,812			-			48,520
General taxes		5,602			9,050			6,258			-			20,910
Total expenses		938,236			392,927			212,522			(738,772	)		804,913
OPERATING INCOME		136,622			60,626			66,570			-			263,818
OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		74,781			(622	)		4,215			(63,005	)		15,369
Interest expense - affiliates		-			(17,990	)		(4,827	)		-			(22,817	)
Interest expense - other		(5,773	)		(6,116	)		(9,804	)		-			(21,693	)
Capitalized interest		6			3,056			1,361			-			4,423
Total other income (expense)		69,014			(21,672	)		(9,055	)		(63,005	)		(24,718	)
INCOME BEFORE INCOME TAXES		205,636			38,954			57,515			(63,005	)		239,100
INCOME TAXES		54,220			12,892			20,572			-			87,684
NET INCOME	$	151,416		$	26,062		$	36,943		$	(63,005	)	$	151,416

134

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
For the Six Months Ended June 30, 2008	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
REVENUES	$	2,164,475		$	1,132,926		$	612,712		$	(1,739,719	)	$	2,170,394
EXPENSES:
Fuel		5,743			568,431			58,065			-			632,239
Purchased power from non-affiliates		427,063			-			-			-			427,063
Purchased power from affiliates		1,734,649			5,070			60,013			(1,739,719	)		60,013
Other operating expenses		67,438			231,340			261,129			24,377			584,284
Provision for depreciation		1,907			56,626			50,087			(2,718	)		105,902
General taxes		10,142			23,074			9,776			-			42,992
Total expenses		2,246,942			884,541			439,070			(1,718,060	)		1,852,493
OPERATING INCOME (LOSS)		(82,467	)		248,385			173,642			(21,659	)		317,901
OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		220,315			(719	)		(15,986	)		(208,588	)		(4,978	)
Interest expense - affiliates		(132	)		(13,209	)		(4,597	)		-			(17,938	)
Interest expense - other		(10,641	)		(49,665	)		(21,650	)		32,916			(49,040	)
Capitalized interest		49			16,084			1,071			-			17,204
Total other income (expense)		209,591			(47,509	)		(41,162	)		(175,672	)		(54,752	)
INCOME BEFORE INCOME TAXES		127,124			200,876			132,480			(197,331	)		263,149
INCOME TAXES (BENEFIT)		(30,954	)		77,752			53,602			4,671			105,071
NET INCOME	$	158,078		$	123,124		$	78,878		$	(202,002	)	$	158,078

135

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
For the Six Months Ended June 30, 2007	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
REVENUES	$	2,094,245		$	1,004,908		$	513,183		$	(1,525,312	)	$	2,087,024
EXPENSES:
Fuel		9,880			436,884			55,651			-			502,415
Purchased power from non-affiliates		349,076			-			-			-			349,076
Purchased power from affiliates		1,515,432			118,727			38,221			(1,525,312	)		147,068
Other operating expenses		81,768			164,789			250,184			-			496,741
Provision for depreciation		922			50,175			45,433			-			96,530
General taxes		10,536			19,618			12,474			-			42,628
Total expenses		1,967,614			790,193			401,963			(1,525,312	)		1,634,458
OPERATING INCOME		126,631			214,715			111,220			-			452,566
OTHER INCOME (EXPENSE):
Miscellaneous income, including
net income from equity investees		188,729			294			9,415			(163,337	)		35,101
Interest expense - affiliates		-			(42,321	)		(9,942	)		-			(52,263	)
Interest expense - other		(7,158	)		(12,876	)		(19,017	)		-			(39,051	)
Capitalized interest		11			5,155			2,466			-			7,632
Total other income (expense)		181,582			(49,748	)		(17,078	)		(163,337	)		(48,581	)
INCOME BEFORE INCOME TAXES		308,213			164,967			94,142			(163,337	)		403,985
INCOME TAXES		54,293			62,181			33,591			-			150,065
NET INCOME	$	253,920		$	102,786		$	60,551		$	(163,337	)	$	253,920

136

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING BALANCE SHEETS
(Unaudited)
As of June 30, 2008	FES		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2	$	-	$	-	$	-		$	2
Receivables-
Customers		117,858		-		-		-			117,858
Associated companies		419,402		259,454		80,249		(285,131	)		473,974
Other		1,475		1,376		5,105		-			7,956
Notes receivable from associated companies		554,279		-		-		-			554,279
Materials and supplies, at average cost		2,942		281,275		205,327		-			489,544
Prepayments and other		141,414		30,300		695		-			172,409
		1,237,372		572,405		291,376		(285,131	)		1,816,022
PROPERTY, PLANT AND EQUIPMENT:
In service		82,280		5,385,410		4,666,202		(391,896	)		9,741,996
Less - Accumulated provision for depreciation		9,411		2,684,494		1,609,851		(169,476	)		4,134,280
		72,869		2,700,916		3,056,351		(222,420	)		5,607,716
Construction work in progress		11,373		1,064,083		145,833		-			1,221,289
		84,242		3,764,999		3,202,184		(222,420	)		6,829,005
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,234,635		-			1,234,635
Long-term notes receivable from associated companies		-		-		62,900		-			62,900
Investment in associated companies		2,677,674		-		-		(2,677,674	)		-
Other		2,323		63,467		202		-			65,992
		2,679,997		63,467		1,297,737		(2,677,674	)		1,363,527
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes		16,722		480,721		-		(249,475	)		247,968
Lease assignment receivable from associated companies		-		67,256		-		-			67,256
Goodwill		24,248		-		-		-			24,248
Property taxes		-		25,007		22,767		-			47,774
Pension assets		3,211		12,206		-		-			15,417
Unamortized sale and leaseback costs		-		23,282		-		50,096			73,378
Other		8,473		58,569		8,813		(47,063	)		28,792
		52,654		667,041		31,580		(246,442	)		504,833
	$	4,054,265	$	5,067,912	$	4,822,877	$	(3,431,667	)	$	10,513,387
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	4,679	$	873,562	$	1,077,289	$	(17,315	)	$	1,938,215
Short-term borrowings-
Associated companies		-		774,490		442,217		-			1,216,707
Other		1,000,000		-		-		-			1,000,000
Accounts payable-
Associated companies		275,820		253,818		93,599		(275,431	)		347,806
Other		81,252		133,486		-		-			214,738
Accrued taxes		1,162		58,976		19,393		(6,993	)		72,538
Other		116,036		98,885		14,607		34,697			264,225
		1,478,949		2,193,217		1,647,105		(265,042	)		5,054,229
CAPITALIZATION:
Common stockholder's equity		2,505,676		1,071,297		1,596,565		(2,667,862	)		2,505,676
Long-term debt and other long-term obligations		41,317		1,312,162		421,815		(1,296,982	)		478,312
		2,546,993		2,383,459		2,018,380		(3,964,844	)		2,983,988
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		1,043,442			1,043,442
Accumulated deferred income taxes		-		-		245,223		(245,223	)		-
Accumulated deferred investment tax credits		-		34,646		24,176		-			58,822
Asset retirement obligations		-		24,274		811,924		-			836,198
Retirement benefits		9,590		56,925		-		-			66,515
Property taxes		-		25,329		22,766		-			48,095
Lease market valuation liability		-		330,457		-		-			330,457
Other		18,733		19,605		53,303		-			91,641
		28,323		491,236		1,157,392		798,219			2,475,170
	$	4,054,265	$	5,067,912	$	4,822,877	$	(3,431,667	)	$	10,513,387

137

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING BALANCE SHEETS
(Unaudited)
As of December 31, 2007	FES		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2	$	-	$	-	$	-		$	2
Receivables-
Customers		133,846		-		-		-			133,846
Associated companies		327,715		237,202		98,238		(286,656	)		376,499
Other		2,845		978		-		-			3,823
Notes receivable from associated companies		23,772		-		69,012		-			92,784
Materials and supplies, at average cost		195		215,986		210,834		-			427,015
Prepayments and other		67,981		21,605		2,754		-			92,340
		556,356		475,771		380,838		(286,656	)		1,126,309
PROPERTY, PLANT AND EQUIPMENT:
In service		25,513		5,065,373		3,595,964		(392,082	)		8,294,768
Less - Accumulated provision for depreciation		7,503		2,553,554		1,497,712		(166,756	)		3,892,013
		18,010		2,511,819		2,098,252		(225,326	)		4,402,755
Construction work in progress		1,176		571,672		188,853		-			761,701
		19,186		3,083,491		2,287,105		(225,326	)		5,164,456
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,332,913		-			1,332,913
Long-term notes receivable from associated companies		-		-		62,900		-			62,900
Investment in associated companies		2,516,838		-		-		(2,516,838	)		-
Other		2,732		37,071		201		-			40,004
		2,519,570		37,071		1,396,014		(2,516,838	)		1,435,817
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes		16,978		522,216		-		(262,271	)		276,923
Lease assignment receivable from associated companies		-		215,258		-		-			215,258
Goodwill		24,248		-		-		-			24,248
Property taxes		-		25,007		22,767		-			47,774
Pension asset		3,217		13,506		-		-			16,723
Unamortized sale and leaseback costs		-		27,597		-		43,206			70,803
Other		22,956		52,971		6,159		(38,133	)		43,953
		67,399		856,555		28,926		(257,198	)		695,682
	$	3,162,511	$	4,452,888	$	4,092,883	$	(3,286,018	)	$	8,422,264
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	-	$	596,827	$	861,265	$	(16,896	)	$	1,441,196
Short-term borrowings-
Associated companies		-		238,786		25,278		-			264,064
Other		300,000		-		-		-			300,000
Accounts payable-
Associated companies		287,029		175,965		268,926		(286,656	)		445,264
Other		56,194		120,927		-		-			177,121
Accrued taxes		18,831		125,227		28,229		(836	)		171,451
Other		57,705		131,404		11,972		36,725			237,806
		719,759		1,389,136		1,195,670		(267,663	)		3,036,902
CAPITALIZATION:
Common stockholder's equity		2,414,231		951,542		1,562,069		(2,513,611	)		2,414,231
Long-term debt and other long-term obligations		-		1,597,028		242,400		(1,305,716	)		533,712
		2,414,231		2,548,570		1,804,469		(3,819,327	)		2,947,943
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		1,060,119			1,060,119
Accumulated deferred income taxes		-		-		259,147		(259,147	)		-
Accumulated deferred investment tax credits		-		36,054		25,062		-			61,116
Asset retirement obligations		-		24,346		785,768		-			810,114
Retirement benefits		8,721		54,415		-		-			63,136
Property taxes		-		25,328		22,767		-			48,095
Lease market valuation liability		-		353,210		-		-			353,210
Other		19,800		21,829		-		-			41,629
		28,521		515,182		1,092,744		800,972			2,437,419
	$	3,162,511	$	4,452,888	$	4,092,883	$	(3,286,018	)	$	8,422,264

138

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
For the Six Months Ended June 30, 2008	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES	$	(138,894	)	$	109,372		$	82,857		$	(8,316	)	$	45,019
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			276,235			179,500			-			455,735
Short-term borrowings, net		700,000			535,705			416,938			-			1,652,643
Redemptions and Repayments-
Long-term debt		(792	)		(285,567	)		(180,334	)		8,316			(458,377	)
Common stock dividend payment		(10,000	)		-			-			-			(10,000	)
Net cash provided from financing activities		689,208			526,373			416,104			8,316			1,640,001
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(20,176	)		(584,151	)		(548,175	)		-			(1,152,502	)
Proceeds from asset sales		-			10,875			-			-			10,875
Sales of investment securities held in trusts		-			-			384,692			-			384,692
Purchases of investment securities held in trusts		-			-			(404,502	)		-			(404,502	)
Loan repayments from (loans to) associated companies, net		(530,508	)		-			69,012			-			(461,496	)
Other		370			(62,469	)		12			-			(62,087	)
Net cash used for investing activities		(550,314	)		(635,745	)		(498,961	)		-			(1,685,020	)
Net change in cash and cash equivalents		-			-			-			-			-
Cash and cash equivalents at beginning of period		2			-			-			-			2
Cash and cash equivalents at end of period	$	2		$	-		$	-		$	-		$	2

139

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
For the Six Months Ended June 30, 2007	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES	$	(77,782	)	$	255,301		$	33,686		$	-		$	211,205
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Equity contribution from parent		700,000			700,000			-			(700,000	)		700,000
Short-term borrowings, net		500,000			-			-			(135,153	)		364,847
Redemptions and Repayments-
Long-term debt		-			(616,792	)		(128,744	)		-			(745,536	)
Short-term borrowings, net		-			(135,153	)		-			135,153			-
Common stock dividend payment		(37,000	)		-			-			-			(37,000	)
Net cash provided from (used for) financing activities		1,163,000			(51,945	)		(128,744	)		(700,000	)		282,311
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(9,466	)		(215,804	)		(77,154	)		-			(302,424	)
Proceeds from asset sales		-			12,120			-			-			12,120
Sales of investment securities held in trusts		-			-			367,924			-			367,924
Purchases of investment securities held in trusts		-			-			(389,286	)		-			(389,286	)
Loan repayments from (loans to) associated companies, net		(376,444	)		-			192,268			-			(184,176	)
Investment in subsidiary		(700,000	)		-			-			700,000			-
Other		692			328			1,306			-			2,326
Net cash provided from (used for) investing activities		(1,085,218	)		(203,356	)		95,058			700,000			(493,516	)
Net change in cash and cash equivalents		-			-			-			-			-
Cash and cash equivalents at beginning of period		2			-			-			-			2
Cash and cash equivalents at end of period	$	2		$	-		$	-		$	-		$	2

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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 – FIRSTENERGY

FirstEnergy’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 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 June 30, 2008, there were no changes in FirstEnergy’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrant’s internal control over financial reporting.

ITEM 4T. CONTROLS AND PROCEDURES – FES, OE, CEI, TE, JCP&L, MET-ED AND PENELEC

(a)   EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Each registrant's chief executive officer and chief financial officer have reviewed and evaluated such 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 such registrant's disclosure controls and procedures are effective and were designed to bring to their attention material information relating to such registrant and its consolidated subsidiaries by others within those entities.

(b)   CHANGES IN INTERNAL CONTROLS

During the quarter ended June 30, 2008, 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.

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PART II. OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 10 and 11 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 1A. RISK FACTORS

FirstEnergy’s Annual Report on Form 10-K for the year ended December 31, 2007 includes a detailed discussion of its risk factors. The information presented below updates certain of those risk factors and should be read in conjunction with the risk factors and information disclosed in FirstEnergy’s Annual Report on Form 10-K.

The Uncertainty of the Form of the Rules Ultimately Adopted By the PUCO to Implement SB221

The PUCO has yet to finalize the rules to implement SB221, including the rules for the filing of ESPs or MROs or rules implementing the other provisions of the legislation. These filing rules may not be finalized before the end of 2008, and were not finalized when the Ohio Companies made their ESP and MRO filings in July 2008. Those filings were made pursuant to proposed rules, subject to such applications being modified to conform to the final rules upon their issuance. Consequently, the uncertainty surrounding the ultimate form of these rules could impact the results FirstEnergy expects to receive from the Ohio Companies’ filings and could negatively impact its results of operations and financial condition.

The Potential Impact of the U.S. Court of Appeals’ July 11, 2008 Decision to Vacate the CAIR Rules and The Uncertainty Surrounding the Form of any Laws, Rules or Regulations That May Take its Place

On July 11, 2008, the United States Court of Appeals for the District of Columbia vacated the CAIR rules. The impacts of this decision may include, but are not limited to, the potential for an asset impairment charge for a portion of FirstEnergy’s annual NOx emission allowances. FirstEnergy continues to consider the implications of the Court’s decision, and currently believes it has no material asset impairment issue. To the extent the laws, rules or regulations that ultimately may replace CAIR differ significantly from the original rules, FirstEnergy’s results of operations and financial condition could be negatively affected.

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
	April 1-30,	May 1-31,	June 1-30,	Second
	2008	2008	2008	Quarter
Total Number of Shares Purchased (a)	237,587	207,833	556,691	1,002,111	��
Average Price Paid per Share	$74.46	$77.77	$80.22	$78.35
Total Number of Shares Purchased
As Part of Publicly Announced Plans
or Programs (b)	-	-	-	-
Maximum Number (or Approximate Dollar
Value) of Shares that May Yet Be
Purchased Under the Plans or Programs	-	-	-	-

(a)

Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock under its 2007 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 2007 Incentive Compensation Plan and the Executive Deferred Compensation Plan, and shares purchased as part of publicly announced plans.

(b)

On December 10, 2007, FirstEnergy’s plan to repurchase up to 16 million shares of its common stock through June 30, 2008, was concluded.

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ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

(a)   The annual meeting of FirstEnergy shareholders was held on May 20, 2008.

(b)   At this meeting, the following persons (comprising all members of the Board) were elected to FirstEnergy's Board of Directors for one-year terms:

	Number of Votes
	For	Withheld
Paul T. Addison	166,788,020	94,286,065
Anthony J. Alexander	166,689,752	94,384,333
Michael J. Anderson	167,838,258	93,235,827
Dr. Carol A. Cartwright	136,292,273	124,781,812
William T. Cottle	137,139,127	123,934,958
Robert B. Heisler, Jr.	166,413,896	94,660,189
Ernest J. Novak, Jr.	166,845,340	94,228,745
Catherine A. Rein	166,260,804	94,813,281
George M. Smart	136,474,908	124,599,177
Wes M. Taylor	166,721,392	94,352,693
Jesse T. Williams, Sr.	136,872,458	124,201,627

(c)   (i)     At this meeting, the appointment of PricewaterhouseCoopers LLP, an independent registered public accounting firm, as auditor for the year 2008 was ratified:

Number of Votes
For	Against	Abstentions
254,692,023	2,847,986	3,534,076

    (ii) At this meeting, a shareholder proposal recommending that the Board of Directors amend the company’s bylaws to reduce the percentage of shareholders required to call a special shareholder meeting was approved (approval required a favorable vote of a majority of the votes cast):

Number of Votes
			Broker
For	Against	Abstentions	Non-Votes
154,287,388	75,561,339	4,966,165	26,259,193

Based on this result, the Board of Directors will further review this proposal.

(iii)   At this meeting, a shareholder proposal recommending that the Board of Directors adopt a policy establishing an engagement process with proponents of shareholder proposals that are supported by a majority of the votes cast was not approved (approval required a favorable vote of a majority of the votes cast):

Number of Votes
			Broker
For	Against	Abstentions	Non-Votes
96,151,699	131,452,822	7,210,371	26,259,193

(iv)   At this meeting, a shareholder proposal recommending that the Board of Directors adopt simple majority shareholder voting was approved (approval required a favorable vote of a majority of the votes cast):

Number of Votes
			Broker
For	Against	Abstentions	Non-Votes
181,558,191	48,325,314	4,931,387	26,259,193

Based on this result, the Board of Directors will further review this proposal.

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(v)   At this meeting, a shareholder proposal recommending that the Board of Directors adopt a majority vote standard for the election of directors was approved (approval required a favorable vote of a majority of the votes cast):

Number of Votes
			Broker
For	Against	Abstentions	Non-Votes
164,594,559	65,276,860	4,943,473	26,259,193

Based on this result, the Board of Directors will further review this proposal.

ITEM 5.   OTHER INFORMATION

Effective August 6, 2008, Mr. Gary R. Leidich, Executive Vice President of FirstEnergy (Company) and President of FirstEnergy Generation, entered into a Special Severance Agreement (Agreement) with the Company. The Agreement shall expire by its terms on December 31, 2009, but will be reviewed annually by the Board of Directors which will decide whether to extend its term for an additional year. If at any time within twenty-four months after a change in control (as defined in the Agreement) Mr. Leidich’s employment is involuntarily terminated for any reason other than cause (as defined in the Agreement) or voluntarily terminated for good reason (as defined in the Agreement), the Company shall pay him a lump-sum severance benefit payable in cash of his full base salary through the date of his termination of employment, plus 2.99 times his annual salary as of the date of his termination of employment, plus the target annual short-term incentive amount in effect for him under the FirstEnergy Corp. 2007 Incentive Compensation Plan.

The description of the potential payments set forth above does not purport to be complete and is qualified in its entirety by reference to the Form of Special Severance Agreements which was filed as Exhibit 10.1 to FirstEnergy’s Form 10-K for the year ended December 31, 2007 and is incorporated herein by reference as part of this item.

ITEM 6.   EXHIBITS

Exhibit Number
FirstEnergy
	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-14(a)
	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
FES
		31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
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-14(a)
		31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
CEI
		31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		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-14(a)
		31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
JCP&L
		31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
Met-Ed
		31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350

144

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-14(a)
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350

Pursuant to reporting requirements of respective financings, FirstEnergy, OE 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, FES, 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.

145

SIGNATURES

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.

August 7, 2008

FIRSTENERGY CORP.

Registrant

FIRSTENERGY SOLUTIONS CORP.

Registrant

OHIO EDISON COMPANY

Registrant

THE CLEVELAND ELECTRIC

ILLUMINATING COMPANY

Registrant

THE TOLEDO EDISON COMPANY

Registrant

METROPOLITAN EDISON COMPANY

Registrant

PENNSYLVANIA ELECTRIC COMPANY

Registrant

/s/  Harvey L. Wagner

Harvey L. Wagner

Vice President, Controller

and Chief Accounting Officer

JERSEY CENTRAL POWER & LIGHT COMPANY

Registrant

/s/  Paulette R. Chatman

Paulette R. Chatman

Controller

(Principal Accounting Officer)

146