FirstEnergy (FE) 10-Q 2009 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, 2009

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
000-53742	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, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company
Yes (  )  No (X)	FirstEnergy Solutions Corp.

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes (X) No (  ) FirstEnergy Corp.

Yes (  ) No (  ) 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 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 3, 2009
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	13,628,447
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 achievements 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 Pennsylvania,

·   the impact of the PUCO’s regulatory process on the Ohio Companies associated with the distribution rate case,

·   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 potential impacts of the U.S. Court of Appeals’ July 11, 2008 decision requiring revisions to 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 that certain generating units may need to be shut down) 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,

·   Met-Ed’s and Penelec’s transmission service charge filings with the PPUC,

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

·   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 changing market conditions that could affect the value of assets held in the registrants’ nuclear decommissioning trusts, pension trusts and other trust funds, and cause FirstEnergy to make additional contributions sooner, or in an amount that is larger than currently anticipated,

·   the ability to access the public securities and other capital and credit markets in accordance with FirstEnergy’s financing plan and the cost of such capital,

·   changes in general economic conditions affecting the registrants,

·   the state of the capital and credit markets affecting the registrants,

·   interest rates and any actions taken by credit rating agencies that could negatively affect the registrants’ access to financing or its costs and increase requirements to post additional collateral to support outstanding commodity positions, LOCs and other financial guarantees,

·   the continuing decline of the national and regional economy and its impact on the registrants’ major industrial and commercial customers,

·   issues concerning the soundness of financial institutions and counterparties with which the registrants do business, and

·   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 for management 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. A security rating is not a recommendation to buy, sell or hold securities that may be subject to revision or withdrawal at any time by the assigning rating organization. Each 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	1-44
	Report of Independent Registered Public Accounting Firm	45
	Consolidated Statements of Income	46
	Consolidated Statements of Comprehensive Income	47
	Consolidated Balance Sheets	48
	Consolidated Statements of Cash Flows	49
FirstEnergy Solutions Corp.
	Management's Narrative Analysis of Results of Operations	50-53
	Report of Independent Registered Public Accounting Firm	54
	Consolidated Statements of Income and Comprehensive Income	55
	Consolidated Balance Sheets	56
	Consolidated Statements of Cash Flows	57
Ohio Edison Company
	Management's Narrative Analysis of Results of Operations	58-59
	Report of Independent Registered Public Accounting Firm	60
	Consolidated Statements of Income and Comprehensive Income	61
	Consolidated Balance Sheets	62
	Consolidated Statements of Cash Flows	63
The Cleveland Electric Illuminating Company
	Management's Narrative Analysis of Results of Operations	64-65
	Report of Independent Registered Public Accounting Firm	66
	Consolidated Statements of Income and Comprehensive Income	67
	Consolidated Balance Sheets	68
	Consolidated Statements of Cash Flows	69
The Toledo Edison Company
	Management's Narrative Analysis of Results of Operations	70-71
	Report of Independent Registered Public Accounting Firm	72
	Consolidated Statements of Income and Comprehensive Income	73
	Consolidated Balance Sheets	74
	Consolidated Statements of Cash Flows	75

i

TABLE OF CONTENTS (Cont'd)

Jersey Central Power & Light Company		Pages
	Management's Narrative Analysis of Results of Operations	76-77
	Report of Independent Registered Public Accounting Firm	78
	Consolidated Statements of Income and Comprehensive Income	79
	Consolidated Balance Sheets	80
	Consolidated Statements of Cash Flows	81
Metropolitan Edison Company
	Management's Narrative Analysis of Results of Operations	82-83
	Report of Independent Registered Public Accounting Firm	84
	Consolidated Statements of Income and Comprehensive Income	85
	Consolidated Balance Sheets	86
	Consolidated Statements of Cash Flows	87
Pennsylvania Electric Company
	Management's Narrative Analysis of Results of Operations	88-89
	Report of Independent Registered Public Accounting Firm	90
	Consolidated Statements of Income and Comprehensive Income	91
	Consolidated Balance Sheets	92
	Consolidated Statements of Cash Flows	93
Combined Management's Discussion and Analysis of Registrant Subsidiaries		94-109
Combined Notes to Consolidated Financial Statements		110-147
Item 3.       Quantitative and Qualitative Disclosures About Market Risk.		148
Item 4.       Controls and Procedures – FirstEnergy.		148
Item 4T.    Controls and Procedures – FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec.		148
Part II.    Other Information
Item 1.       Legal Proceedings.		149
Item 1A.    Risk Factors.		149
Item 2.       Unregistered Sales of Equity Securities and Use of Proceeds.		149
Item 4.       Submission of Matters to a Vote of Security Holders.		149-150
Item 6.       Exhibits.		151-154

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
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
FEV	FirstEnergy Ventures Corp., invests in certain unregulated enterprises and business ventures
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
Shelf Registrants	OE, CEI, TE, JCP&L, Met-Ed and Penelec
Shippingport	Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
Signal Peak	A joint venture between FirstEnergy Ventures Corp. and Boich Companies, that owns mining and    coal transportation operations near Roundup, Montana
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
Utilities	OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec
Waverly	The Waverly Power and Light Company, a wholly owned subsidiary of Penelec
The following abbreviations and acronyms are used to identify frequently used terms in this report:
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
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
CTC	Competitive Transition Charge
DOJ	United States Department of Justice
DPA	Department of the Public Advocate, Division of Rate Counsel
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 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 Bond
FSP	FASB Staff Position
FSP FAS 115-2 and    FAS 124-2	FSP FAS 115-2 and FAS 124-2, "Recognition and Presentation of Other-Than-Temporary     Impairments"
FSP FAS 132(R)-1	FSP FAS 132(R)-1, "Employers' Disclosures about Postretirement Benefit Plan Assets"
FSP FAS 157-4	FSP FAS 157-4, "Determining Fair Value When the Volume and Level of Activity for the Asset or     Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly"
GAAP	Accounting Principles Generally Accepted in the United States
GHG	Greenhouse Gases
ICE	Intercontinental Exchange
IRS	Internal Revenue Service
kV	Kilovolt
KWH	Kilowatt-hours
LED	Light-emitting Diode
LIBOR	London Interbank Offered Rate
LOC	Letter of Credit
MISO	Midwest Independent Transmission System Operator, Inc.
Moody's	Moody's Investors Service, Inc.
MRO	Market Rate Offer
MW	Megawatts
MWH	Megawatt-hours
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NJBPU	New Jersey Board of Public Utilities
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
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
OVEC	Ohio Valley Electric Corporation
PCRB	Pollution Control Revenue Bond
PJM	PJM Interconnection L. L. C.
PLR	Provider of Last Resort; an electric utility's obligation to provide generation service to customers    whose alternative supplier fails to deliver service
PPUC	Pennsylvania Public Utility Commission
PSA	Power Supply Agreement
PUCO	Public Utilities Commission of Ohio
RCP	Rate Certainty Plan
RFP	Request for Proposal
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 71	SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
SFAS 107	SFAS No. 107, "Disclosure about Fair Value of Financial Instruments"
SFAS 115	SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities"
SFAS 133	SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities"
SFAS 140	SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments    of Liabilities – a replacement of FASB Statement No. 125”

iv

GLOSSARY OF TERMS, Cont'd.

SFAS 157	SFAS No. 157, "Fair Value Measurements"
SFAS 160	SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements – an Amendment    of ARB No. 51"
SFAS 166	SFAS No. 166, “Accounting for Transfers of Financial Assets – an amendment of FASB    Statement No. 140”
SFAS 167	SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)”
SFAS 168	SFAS No. 168, “The FASB Accounting Standards CodificationTM and the Hierarchy of Generally    Accepted Accounting Principles – a replacement of FASB Statement No. 162”
SIP	State Implementation Plan(s) Under the Clean Air Act
SNCR	Selective Non-Catalytic Reduction
SO2	Sulfur Dioxide
TBC	Transition Bond Charge
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 2009 was $408 million, or basic and diluted earnings of $1.36 per share of common stock, compared with net income of $263 million, or basic earnings of $0.86 per share of common stock ($0.85 diluted) in the second quarter of 2008. Results in the second quarter of 2009 include a gain of $0.52 per share resulting from the sale of FirstEnergy’s 9% participation interest in OVEC. Net income in the first six months of 2009 was $523million, or basic and diluted earnings of $1.75per share of common stock, compared with net income of $540 million, or basic earnings of $1.77per share of common stock ($1.75diluted) in the first six months of 2008.

Change in Basic Earnings Per Share From Prior Year Periods	Three Months Ended June 30				Six Months Ended June 30
Basic Earnings Per Share – 2008		$	0.86			$	1.77
Gain on non-core asset sales	0.52				0.46
Regulatory charges – 2009	-				(0.55			)
Income tax resolution – 2009	-				0.04
Organizational restructuring costs – 2009	(0.01			)	(0.06			)
Debt redemption premium / Penelec strike costs – 2009	(0.01			)	(0.01			)
Litigation settlement – 2008	(0.03			)	(0.03			)
Trust securities impairment	0.04				(0.01			)
Revenues (excluding asset sales)	(0.44			)	(0.26			)
Fuel and purchased power	0.17				(0.07			)
Transmission costs	0.20				0.26
Amortization of regulatory assets, net	(0.08			)	0.04
Other expenses		0.14				0.17
Basic Earnings Per Share – 2009		$	1.36			$	1.75

Regulatory Matters

Ohio

On May 14, 2009, FirstEnergy announced that an auction to secure generation supply and pricing for the Ohio Companies for the period June 1, 2009 through May 31, 2011, was completed and the results were approved by the PUCO. The auction resulted in an average weighted wholesale price for generation and transmission of 6.15 cents per KWH. FES was a successful bidder for 51% of the Ohio Companies’ PLR generation requirements. Twelve bidders qualified to participate in the auction with nine successful bidders each securing a portion of the Ohio Companies’ load.  Subsequent to the auction FES purchased tranches totaling an additional 11% of the load from other winning bidders. Effective August 1, 2009, FES is supplying 62% of the Ohio Companies’ PLR generation requirements.

On June 17, 2009, the PUCO modified rules that implement the alternative energy portfolio standards created by SB221, including the incorporation of energy efficiency requirements, long-term forecast and greenhouse gas reporting and CO2 control planning. The PUCO filed the rules with the Joint Committee on Agency Rule Review on July 7, 2009, after which begins a 65-day review period. The Ohio Companies and one other party filed applications for rehearing on the rules with the PUCO on July 17, 2009.

On July 27, 2009, the Ohio Companies filed applications with the PUCO to recover three different categories of deferred distribution costs on an accelerated basis. In the Ohio Companies' Amended ESP, the PUCO approved the recovery of these deferrals, with collection originally set to begin in January 2011 and to continue over a 5 or 25 year period. The principal amount plus carrying charges through August 31, 2009 for these deferrals is a total of $298.4 million. If the applications are approved, recovery of this amount, together with carrying charges calculated as approved in the Amended ESP, will be collected in the 18 non-summer months from September 2009 through May 2011, subject to reconciliation until fully collected, with $165 million of the above amount being recovered from residential customers, and $133.4 million being recovered from non-residential customers. Pursuant to the applications, customers would pay significantly less over the life of the recovery of the deferral through the reduction in carrying charges as compared to the expected recovery under the previously approved recovery mechanism.

1

Pennsylvania

On May 28, 2009, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC riders for the period June 1, 2009 through May 31, 2010, as required in connection with the PPUC’s January 2007 rate order. For Penelec’s customers the new TSC resulted in an approximate 1% decrease in monthly bills, reflecting projected PJM transmission costs as well as a reconciliation for costs previously incurred. The TSC for Met-Ed’s customers increased to recover the additional PJM charges paid by Met-Ed in the previous year and to reflect updated projected costs. In order to gradually transition customers to the higher rate, the PPUC approved Met-Ed’s proposal to continue to recover the prior period deferrals allowed in the PPUC’s May 2008 Order and defer $57.5 million of projected costs to a future TSC to be fully recovered by December 31, 2010. Under this proposal, monthly bills for Met-Ed’s customers are expected to increase approximately 9.4% for the period June 2009 through May 2010.

On February 20, 2009, Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, 2011, through May 31, 2013. The companies’ plan is designed to provide adequate and reliable service through a prudent mix of long-term, short-term and spot market generation supply as required by Act 129. The plan proposes a staggered procurement schedule, which varies by customer class. On March 30, 2009, Met-Ed and Penelec filed direct testimony pursuant to the March 5, 2009 case schedule issued by the ALJ. The PPUC is expected to issue a final decision in November 2009.

On June 18, 2009, the PPUC issued standards for the smart meter technology procurement and installation plans required by Act 129 to be filed by the state’s large electric distribution companies by August 14, 2009. The PPUC also provided guidance on the procedures to be followed for submittal, review and approval of all aspects of the smart meter plans. On June 18, 2009, the PPUC also adopted a total resource cost test to analyze the costs and benefits of energy efficiency and conservation plans filed under Act 129. On July 1, 2009, Met-Ed, Penelec and Penn filed energy efficiency and conservation plans in accordance with the requirements of Act 129.

FERC

On July 31, 2009, FirstEnergy announced its intention to withdraw its transmission facilities from MISO and realign them into PJM. The effect of the realignment is to consolidate essentially all of FirstEnergy's generation and transmission operations within a single RTO. FirstEnergy expects to make a filing with the FERC in August 2009 to obtain the necessary regulatory approvals. FirstEnergy plans to integrate its operations into PJM by June 1, 2011. FERC approval will be sought by the end of 2009 in order to allow FirstEnergy's load and generation operations currently in MISO to participate in the PJM capacity auction held in May 2010 for service beginning June 1, 2013.

Operational Matters

Recessionary Market Conditions and Weather Impacts

The demand for electricity produced and sold by FirstEnergy’s competitive subsidiary, FES, along with the value of that electricity, is materially impacted by conditions in competitive power markets, global economic activity, economic activity in the Midwest and Mid-Atlantic regions, and weather conditions in FirstEnergy’s service territories. The current recessionary economic conditions, particularly in the automotive and steel industries, compounded by unusually mild regional summertime temperatures, have directly impacted FirstEnergy’s operations and revenues over the last six to nine months.

The level of demand for electricity directly impacts FirstEnergy’s distribution, transmission and generation revenues, the quantity of electricity produced, purchased power expense and fuel expense.  FirstEnergy has taken various actions and instituted a number of changes in operating practices to mitigate these external influences. These actions include employee severances, wage reductions, employee and retiree benefit changes, reduced levels of overtime and the use of fewer contractors. However, the continuation of recessionary economic conditions, coupled with unusually mild weather patterns and the resulting impact on electricity prices and demand could impact FirstEnergy's future operating performance and financial condition and may require further changes in FirstEnergy’s operations.

Refueling Outages

On May 13, 2009, the Perry Plant returned to service after completing its 12th refueling and maintenance outage which began on February 23, 2009. On May 21, 2009, the Beaver Valley Unit 1 returned to service after completing its 19th refueling outage which began on April 20, 2009. Several safety inspections and maintenance projects were completed during the outages which were designed to facilitate the continued safe and reliable operations of the units.

2

 FES Retail Activities

As of August 1, 2009, FES has signed 50 government aggregation contracts that will provide discounted generation prices to approximately 600,000 residential and small commercial customers. The governmental aggregator may choose between a graduated or flat percentage discount. The graduated discount plan offers savings of 10%, 6%, 5%, and 4% in the years 2009-2012, respectively. The flat percentage contract offers a 6% discount through the end of the contract. Discounts will be based on the generation price customers would have been charged if they purchased electric generation service from their electric utility and will be effective beginning in late summer or early fall.

Union Contracts

On May 21, 2009, 517 Penelec employees, represented by the International Brotherhood of Electrical Workers (IBEW) Local 459, elected to strike. In response, on May 22, 2009, Penelec implemented its work-continuation plan to use nearly 400 non-represented employees with previous line experience and training drawn from Penelec and other FirstEnergy operations to perform service reliability and priority maintenance work in Penelec’s service territory. Penelec's IBEW Local 459 employees ratified a three-year contract agreement on July 19, 2009, and returned to work on July 20, 2009.

On June 26, 2009, FirstEnergy announced that seven of its union locals, representing about 2,600 employees, have ratified contract extensions. These unions include employees from Penelec, Penn, CEI, OE and TE, along with certain power plant employees.

On July 8, 2009, FirstEnergy announced that employees of Met-Ed represented by IBEW Local 777 ratified a two-year contract.  Union members had been working without a contract since the previous agreement expired on April 30, 2009.

Voluntary Early Retirement Program

In June 2009, FirstEnergy offered a Voluntary Enhanced Retirement Option (VERO), which provides additional benefits for qualified employees who elect to retire.  As of July 31, 2009, the VERO was accepted by 382 non-represented employees and 225 employees represented by unions.

Financial Matters

Rating Agency Actions

On June 17, 2009, Moody’s issued a report affirming FirstEnergy’s Baa3 and FES’ Baa2 credit ratings and maintained its stable outlook. On July 9, 2009, S&P reaffirmed ratings on FirstEnergy and its subsidiaries, including its BBB corporate credit rating, and maintained its stable outlook.

Financing Activities

On April 24, 2009, TE issued $300 million of 7.25% Senior Secured Notes due 2020 and used the net proceeds to repay short-term borrowings, to fund capital expenditures and for other general corporate purposes.

On June 16, 2009, NGC issued a total of approximately $487.5 million in principal amount of FMBs, of which $107.5 million related to one new refunding series of PCRBs and approximately $380 million related to amendments to existing letter of credit and reimbursement agreements supporting seven other series of PCRBs. Similarly, FGCO issued a total of approximately $395.9 million in principal amount of FMBs, of which $247.7 million related to three new refunding series of PCRBs and approximately $148.2 million related to amendments to existing letter of credit and reimbursement agreements supporting two other series of PCRBs. In addition, on June 16, 2009, NGC issued an FMB in a principal amount of up to $500 million in connection with its guaranty of FES’ obligations to post and maintain collateral under the PSA entered into by FES with the Ohio Companies as a result of the May 13-14, 2009 CBP auction.

On June 30, 2009, NGC issued a total of approximately $273.3 million in principal amount of FMBs, of which approximately $92 million related to three existing series of PCRBs and approximately $181.3 million related to amendments to existing letter of credit and reimbursement agreements supporting three other series of PCRBs. FGCO issued a total of approximately $52.1 million in principal amount of FMBs related to three existing series of PCRBs.

On June 30, 2009, Penn privately placed $100 million of FMBs having a fixed interest rate of 6.09%, and maturing on June 30, 2022. The proceeds were used by Penn to repurchase equity from OE and for capital expenditures.

3

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 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.

·   Competitive Energy Services supplies the electric power needs of end-use customers through retail and wholesale arrangements, including associated company power sales to meet 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, Michigan and Illinois. This business segment owns or leases and operates 19 generating facilities with a net demonstrated capacity of 13,710 MW and also purchases electricity to meet sales obligations. The segment's net income is derived primarily 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 FirstEnergy's Ohio Companies. The segment's net income is derived primarily from electric generation sales revenues (including transmission) less the cost of power purchased through the Ohio Companies' CBP and transmission and ancillary costs charged by MISO to deliver energy to retail customers.

RESULTS OF OPERATIONS

The financial results discussed below include revenues and expenses from transactions among FirstEnergy's business segments. A reconciliation of segment financial results is provided in Note 11 to the consolidated financial statements. Earnings by major business segment were as follows:

	Three Months Ended June 30									Six Months Ended June 30
							Increase									Increase
	2009			2008			(Decrease)			2009			2008			(Decrease)
	(In millions, except per share data)
Earnings By Business Segment:
Energy delivery services	$	133		$	193		$	(60	)	$	91		$	372		$	(281	)
Competitive energy services		276			66			210			431			153			278
Ohio transitional generation services		21			20			1			45			43			2
Other and reconciling adjustments*		(16	)		(16	)		-			(34	)		(29	)		(5	)
Total	$	414		$	263		$	151		$	533		$	539		$	(6	)
Basic Earnings Per Share	$	1.36		$	0.86		$	0.50		$	1.75		$	1.77		$	(0.02	)
Diluted Earnings Per Share	$	1.36		$	0.85		$	0.51		$	1.75		$	1.75		$	-
* Consists primarily of interest expense related to holding company debt, corporate support services revenues and expenses, noncontrolling interests and the elimination of intersegment transactions.

4

Summary of Results of Operations – Second Quarter 2009 Compared with Second Quarter 2008

Financial results for FirstEnergy's major business segments in the second quarter of 2009 and 2008 were as follows:

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
Second Quarter 2009 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	1,797		$	205		$	860		$	-		$	2,862
Other		127			299			8			(25	)		409
Internal		-			839			-			(839	)		-
Total Revenues		1,924			1,343			868			(864	)		3,271
Expenses:
Fuel		-			276			-			-			276
Purchased power		864			186			813			(839	)		1,024
Other operating expenses		314			315			14			(31	)		612
Provision for depreciation		110			68			-			7			185
Amortization of regulatory assets		184			-			49			-			233
Deferral of new regulatory assets		-			-			(45	)		-			(45	)
General taxes		152			25			2			5			184
Total Expenses		1,624			870			833			(858	)		2,469
Operating Income		300			473			35			(6	)		802
Other Income (Expense):
Investment income		35			6			-			(14	)		27
Interest expense		(114	)		(32	)		-			(60	)		(206	)
Capitalized interest		1			14			-			18			33
Total Other Expense		(78	)		(12	)		-			(56	)		(146	)
Income Before Income Taxes		222			461			35			(62	)		656
Income taxes		89			185			14			(40	)		248
Net Income		133			276			21			(22	)		408
Less: Noncontrolling interest income (loss)		-			-			-			(6	)		(6	)
Earnings available to FirstEnergy Corp.	$	133		$	276		$	21		$	(16	)	$	414

5

							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		-			316			-			-			316
Purchased power		998			221			555			(704	)		1,070
Other operating expenses		413			312			81			(25	)		781
Provision for depreciation		104			59			-			5			168
Amortization of regulatory assets, net		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
Less: Noncontrolling interest income		-			-			-			-			-
Earnings available to FirstEnergy Corp.	$	193		$	66		$	20		$	(16	)	$	263
Changes Between Second Quarter 2009 and
Second Quarter 2008 Financial Results
Increase (Decrease)
Revenues:
External
Electric	$	(233	)	$	(119	)	$	190		$	-		$	(162	)
Other		(25	)		248			(5	)		(30	)		188
Internal		-			135			-			(135	)		-
Total Revenues		(258	)		264			185			(165	)		26
Expenses:
Fuel		-			(40	)		-			-			(40	)
Purchased power		(134	)		(35	)		258			(135	)		(46	)
Other operating expenses		(99	)		3			(67	)		(6	)		(169	)
Provision for depreciation		6			9			-			2			17
Amortization of regulatory assets		(51	)		-			38			-			(13	)
Deferral of new regulatory assets		98			-			(45	)		-			53
General taxes		3			1			-			-			4
Total Expenses		(177	)		(62	)		184			(139	)		(194	)
Operating Income		(81	)		326			1			(26	)		220
Other Income (Expense):
Investment income		(5	)		14			1			1			11
Interest expense		(14	)		6			-			(10	)		(18	)
Capitalized interest		-			4			-			16			20
Total Other Expense		(19	)		24			1			7			13
Income Before Income Taxes		(100	)		350			2			(19	)		233
Income taxes		(40	)		140			1			(13	)		88
Net Income		(60	)		210			1			(6	)		145
Less: Noncontrolling interest income		-			-			-			(6	)		(6	)
Earnings available to FirstEnergy Corp.	$	(60	)	$	210		$	1		$	-		$	151

6

Energy Delivery Services – Second Quarter 2009 Compared with Second Quarter 2008

Net income decreased $60 million to $133 million in the second quarter of 2009 compared to $193 million in the second quarter of 2008, primarily due to lower revenues and increased amortization of regulatory assets, partially offset by lower purchased power and other operating expenses.

Revenues –

The decrease in total revenues resulted from the following sources:

	Three Months
	Ended June 30
Revenues by Type of Service	2009		2008		Decrease
	(In millions)
Distribution services	$	813	$	919	$	(106)
Generation sales:
Retail		718		772		(54)
Wholesale		162		252		(90)
Total generation sales		880		1,024		(144)
Transmission		188		196		(8)
Other		43		43		-
Total Revenues	$	1,924	$	2,182	$	(258)

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

Electric Distribution KWH Deliveries
Residential	(2.8	)%
Commercial	(3.8	)%
Industrial	(20.8	)%
Total Distribution KWH Deliveries	(9.4	)%

Lower deliveries to residential customers reflected decreased weather-related usage in the second quarter of 2009, as heating and cooling degree days decreased by 2% and 23%, respectively, from the same period in 2008. The decrease in distribution deliveries to commercial and industrial customers was primarily due to economic conditions in FirstEnergy's service territory. In the industrial sector, KWH deliveries declined to major automotive (34.8%) and  steel (50.7%). Transition charges for OE and TE that ceased effective January 1, 2009 with the full recovery of related costs and the Transition rate reduction for CEI effective June 1, 2009, were offset by PUCO-approved distribution rate increases (see Regulatory Matters – Ohio).

The following table summarizes the price and volume factors contributing to the $144 million decrease in generation revenues in the second quarter of 2009 compared to the second quarter of 2008:

Sources of Change in Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of 9.5 % decrease in sales volumes	$	(73	)
Change in prices		19
		(54	)
Wholesale:
Effect of 12.7 % decrease in sales volumes		(32	)
Change in prices		(58	)
		(90	)
Net Decrease in Generation Revenues	$	(144	)

The decrease in retail generation sales volumes was primarily due to weakened economic conditions and the lower weather-related usage described above. The increase in retail generation prices during the second quarter of 2009 reflected increased generation rates for JCP&L resulting from the New Jersey BGS auction and for Penn under its RFP process. Wholesale generation sales decreased principally as a result of JCP&L selling less available power from NUGs due to the termination of a NUG purchase contract in October 2008. The decrease in prices reflected lower spot prices for PJM market participants.

7

Transmission revenues decreased $8 million primarily due to lower PJM transmission revenues partially offset by higher transmission rates for Met-Ed and Penelec resulting from the annual update to their TSC riders in June 2008 and 2009. Met-Ed and Penelec defer the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings (see Regulatory Matters – Pennsylvania).

Expenses –

Total expenses decreased by $177 million due to the net impact of the following:

· Purchased power costs were $134million lower in the second quarter of 2009 due to lower volume requirements and an increase 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	$	45
Change due to decreased volumes		(165	)
		(120	)
Purchases from FES:
Change due to decreased unit costs		(7	)
Change due to increased volumes		15
		8
Increase in NUG costs deferred		(22	)
Net Decrease in Purchased Power Costs	$	(134	)

· PJM transmission expenses were lower by $70 million resulting from reduced volumes and congestion costs.

·   Contractor and material costs decreased $18 million due primarily to reduced maintenance activities as more work was devoted to capital projects.

· Labor and employee benefits decreased $13 million as a result of FirstEnergy cost control initiatives.

·   Storm related costs were $2 million higher than in the second quarter 2008.

· Amortization of regulatory assets decreased $51 million due primarily to the cessation of transition cost amortizations for OE and TE, partially offset by PJM transmission cost amortization in the second quarter of 2009.

·   The deferral of new regulatory assets decreased by $98 million in the second quarter of 2009 principally due to the absence of PJM transmission cost deferrals and RCP distribution cost deferrals by the Ohio Companies.

·   Depreciation expense increased $6 million due to property additions since the second quarter of 2008.

·   General taxes increased $3 million primarily due to higher property taxes associated with the property additions noted above.

Other Expense –

Other expense increased $19million in the second quarter of 2009 compared to the second quarter of 2008 due to lower investment income of $5million, reflecting reduced loan balances to the regulated money pool, and higher interest expense (net of capitalized interest) of $14million, reflecting $600 million of senior notes issuances by JCP&L and Met-Ed in January 2009, and $300 million by TE in April 2009.

8

Competitive Energy Services – Second Quarter 2009 Compared with Second Quarter 2008

Net income for this segment was $276 million in the second quarter of 2009 compared to $66 million in the same period in 2008. The $210 million increase in net income principally reflects FGCO's $252 million gain from the sale of 9% of its participation in OVEC ($158 million after tax) and an increase in gross sales margins.

Revenues –

Total revenues increased $264million in the second quarter of 2009 due to the OVEC sale described above and higher unit prices on affiliated generation sales to the Ohio Companies, partially offset by lower non-affiliated generation sales volumes.

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

	Three Months
	Ended June 30				Increase
Revenues By Type of Service	2009		2008		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	83	$	154	$	(71	)
Wholesale		122		170		(48	)
Total Non-Affiliated Generation Sales		205		324		(119	)
Affiliated Generation Sales		839		704		135
Transmission		16		33		(17	)
Sale of OVEC participation interest		252		-		252
Other		31		18		13
Total Revenues	$	1,343	$	1,079	$	264

The lower retail revenues reflect the expiration of certain government aggregation programs in Ohio at the end of 2008 that were supplied by FES, partially offset by the acquisition of new retail customer contracts in the MISO and PJM markets in the second quarter of 2009. As of August 1, 2009, FES has signed new government aggregation contracts with 50 communities that will provide discounted generation prices to approximately 600,000 residential and small commercial customers. The retail sales volumes associated with these new contracts are expected to result in an increased level of retail revenues in the second half of 2009 as compared to results for the period ended June 30, 2009.

Lower non-affiliated wholesale revenues resulted from lower capacity prices and sales volumes in both the PJM and MISO markets. The increased affiliated company generation revenues were due to higher unit prices for sales to the Ohio Companies under a PSA in April and May 2009 and the CBP in June 2009 (see Regulatory Matters – Ohio), partially offset by lower unit prices to the Pennsylvania Companies and a decrease in sales volumes to the Ohio Companies. Increased sales volumes to the Pennsylvania Companies reflect FES’ sales to Met-Ed and Penelec, following the expiration of a third-party supply contract at the end of 2008. While unit prices for each of the Pennsylvania Companies did not change, the mix of sales among the companies caused the composite price to decline. FES supplied 100% of the power for the Ohio Companies’ PLR service in April and May 2009 and approximately 56% of the Ohio Companies' supply needs for June 2009. Subsequent to the Ohio Companies’ CBP, FES purchased additional tranches from other winning bidders and effective August 1, 2009, FES will supply 62% of the Ohio Companies’ PLR generation requirements.

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 58.7 % decrease in sales volumes	$	(91	)
Change in prices		20
		(71	)
Wholesale:
Effect of 36.2 % decrease in sales volumes		(61	)
Change in prices		13
		(48	)
Net Decrease in Non-Affiliated Generation Revenues	$	(119	)

9

Source of Change in Affiliated Generation Revenues	Increase (Decrease)
	(In millions)
Ohio Companies:
Effect of 13.2 % decrease in sales volumes	$	(74	)
Change in prices		201
		127
Pennsylvania Companies:
Effect of 10 % increase in sales volumes		15
Change in prices		(7	)
		8
Net Increase in Affiliated Generation Revenues	$	135

Transmission revenues decreased $17 million due primarily to reduced loads following the termination of the government aggregation programs mentioned above. The increase in other revenues reflected NGC's increased rental income associated with its acquisition of additional equity interests in the Perry and Beaver Valley Unit 2 leases.

Expenses -

Total expenses decreased $62 million in the second quarter of 2009 due to the following factors:

·   Fuel costs decreased $40 million due to decreased generation volumes ($70 million) partially offset by higher unit prices ($30 million). The increased unit prices, which are expected to continue for the remainder of 2009, primarily reflect higher costs for eastern coal.

·   Purchased power costs decreased $35 million due primarily to lower unit costs ($34 million) and lower volume requirements ($1 million).

·   Fossil operating costs decreased $28 million due to a reduction in contractor and material costs ($18 million) and lower labor and employee benefit expenses ($10 million), reflecting FirstEnergy’s cost control initiatives.

·   Nuclear operating costs decreased $7 million due to lower labor and employee benefit expenses, partially offset by higher expenses associated with the 2009 Perry and Beaver Valley refueling outages and the Davis-Besse maintenance outage.

·   Other operating expenses increased $22 million due primarily to increased intersegment billings for leasehold costs from the Ohio Companies.

·   Transmission expense increased $17 million due primarily to increased net congestion and loss expenses in PJM.

      · Higher depreciation expense of $9 million was due primarily to NGC's increased ownership interests in Perry and Beaver Valley Unit 2 following its purchase of lease equity interests.

Other Expense –

Total other expense in the second quarter of 2009 was $24million lower than the second quarter of 2008, primarily due to a $16 million decrease in trust securities impairments and a $10 million decrease in interest expense (net of capitalized interest).

Ohio Transitional Generation Services – Second Quarter 2009 Compared with Second Quarter 2008

Net income for this segment increased to $21million in the second quarter of 2009 from $20 million in the same period of 2008. Higher generation revenues and lower operating expenses were partially offset by higher purchased power costs.

10

Revenues –

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

	Three Months
	Ended June 30
Revenues by Type of Service	2009		2008		Increase (Decrease)
	(In millions)
Generation sales:
Retail	$	796	$	587	$	209
Wholesale		-		3		(3	)
Total generation sales		796		590		206
Transmission		71		93		(22	)
Other		1		-		1
Total Revenues	$	868	$	683	$	185

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

Source of Change in Retail Generation Revenues	Increase
	(In millions)
Effect of 4.4% increase in sales volumes	$	26
Change in prices		183
Total Increase in Retail Generation Revenues	$	209

The increase in generation sales was primarily due to reduced customer shopping as most of the Ohio Companies' customers returned to PLR service in December 2008 following the expiration of certain government aggregation programs in Ohio. Average prices increased primarily due to an increase in the Ohio Companies' fuel cost recovery rider that was effective from January through May 2009. Effective June 1, 2009, the transmission tariff ended and the recovery of transmission costs is included in the generation rate established under the Ohio Companies' CBP.

Decreased transmission revenue of $22 million resulted from the termination of the transmission tariff (as discussed above) and reduced MISO revenues, partially offset by higher sales volumes. The difference between transmission revenues accrued and transmission costs incurred is deferred, resulting in no material impact to current period earnings.

Expenses -

Purchased power costs were $258million higher due primarily to higher unit costs and volumes. The factors contributing to the higher costs are summarized in the following table:

Source of Change in Purchased Power	Increase
	(In millions)
Change due to increased unit costs	$	239
Change due to increased volumes		19
	$	258

The increase in purchased volumes was due to the higher retail generation sales requirements described above. The higher unit costs reflect the results of the Ohio Companies' power supply procurement processes for retail customers during the second quarter of 2009 (see Regulatory Matters – Ohio).

Other operating expenses decreased $67 million due to lower MISO transmission-related expenses ($43 million) and increased intersegment credits related to the Ohio Companies' generation leasehold interests. The amortization of regulatory assets increased by $38 million in the second quarter of 2009 due primarily to increased MISO transmission cost amortization. The deferral of new regulatory assets increased by $45 million due to CEI’s deferral of purchased power costs as approved by the PUCO.

11

Summary of Results of Operations – First Six Months of 2009 Compared with the First Six Months of 2008

Financial results for FirstEnergy's major business segments in the first six months of 2009 and 2008 were as follows:

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
First Six Months 2009 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	3,756		$	485		$	1,762		$	-		$	6,003
Other		277			354			18			(47	)		602
Internal		-			1,732			-			(1,732	)		-
Total Revenues		4,033			2,571			1,780			(1,779	)		6,605
Expenses:
Fuel		-			588			-			-			588
Purchased power		1,842			346			1,711			(1,732	)		2,167
Other operating expenses		794			670			32			(57	)		1,439
Provision for depreciation		219			132			-			11			362
Amortization of regulatory assets		547			-			95			-			642
Deferral of new regulatory assets		-			-			(136	)		-			(136	)
General taxes		320			57			4			14			395
Total Expenses		3,722			1,793			1,706			(1,764	)		5,457
Operating Income		311			778			74			(15	)		1,148
Other Income (Expense):
Investment income		64			(23	)		1			(26	)		16
Interest expense		(225	)		(60	)		-			(115	)		(400	)
Capitalized interest		2			24			-			35			61
Total Other Expense		(159	)		(59	)		1			(106	)		(323	)
Income Before Income Taxes		152			719			75			(121	)		825
Income taxes		61			288			30			(77	)		302
Net Income		91			431			45			(44	)		523
Less: Noncontrolling interest income (loss)		-			-			-			(10	)		(10	)
Earnings available to FirstEnergy Corp.	$	91		$	431		$	45		$	(34	)	$	533

12

							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		1			643			-			-			644
Purchased power		1,980			427			1,143			(1,480	)		2,070
Other operating expenses		858			621			158			(57	)		1,580
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			(1,513	)		5,322
Operating Income		737			325			71			67			1,200
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			(60	)		887
Income taxes		248			103			28			(32	)		347
Net Income		372			153			43			(28	)		540
Less: Noncontrolling interest income		-			-			-			1			1
Earnings available to FirstEnergy Corp.	$	372		$	153		$	43		$	(29	)	$	539
Changes Between First Six Months 2009
and First Six Months 2008
Financial Results Increase (Decrease)
Revenues:
External
Electric	$	(324	)	$	(128	)	$	401		$	-		$	(51	)
Other		(37	)		263			(11	)		(81	)		134
Internal		-			252			-			(252	)		-
Total Revenues		(361	)		387			390			(333	)		83
Expenses:
Fuel		(1	)		(55	)		-			-			(56	)
Purchased power		(138	)		(81	)		568			(252	)		97
Other operating expenses		(64	)		49			(126	)		-			(141	)
Provision for depreciation		9			20			-			1			30
Amortization of regulatory assets		63			-			75			-			138
Deferral of new regulatory assets		198			-			(131	)		-			67
General taxes		(2	)		1			1			-			-
Total Expenses		65			(66	)		387			(251	)		135
Operating Income		(426	)		453			3			(82	)		(52	)
Other Income (Expense):
Investment income		(21	)		(9	)		1			12			(17	)
Interest expense		(22	)		12			-			(23	)		(33	)
Capitalized interest		1			7			-			32			40
Total Other Expense		(42	)		10			1			21			(10	)
Income Before Income Taxes		(468	)		463			4			(61	)		(62	)
Income taxes		(187	)		185			2			(45	)		(45	)
Net Income		(281	)		278			2			(16	)		(17	)
Less: Noncontrolling interest income		-			-			-			(11	)		(11	)
Earnings available to FirstEnergy Corp.	$	(281	)	$	278		$	2		$	(5	)	$	(6	)

13

Energy Delivery Services – First Six Months of 2009 Compared to First Six Months of 2008

Net income decreased $281 million to $91 million in the first six months of 2009 compared to $372 million in the first six months of 2008, primarily due to decreased revenues and increased amortization of regulatory assets, partially offset by lower purchased power and other operating expenses.

Revenues –

The decrease in total revenues resulted from the following sources:

	Six Months
	Ended June 30				Increase
Revenues by Type of Service	2009		2008		(Decrease)
	(In millions)
Distribution services	$	1,662	$	1,874	$	(212	)
Generation sales:
Retail		1,531		1,562		(31	)
Wholesale		349		471		(122	)
Total generation sales		1,880		2,033		(153	)
Transmission		396		393		3
Other		95		94		1
Total Revenues	$	4,033	$	4,394	$	(361	)

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

Electric Distribution KWH Deliveries
Residential	(1.3) %
Commercial	(3.9) %
Industrial	(19.2) %
Total Distribution KWH Deliveries	(8.0) %

The lower revenues from distribution deliveries were driven by the reductions in sales volume. The decreases in distribution deliveries to commercial and industrial customers were primarily due to economic conditions in FirstEnergy's service territory. In the industrial sector, KWH deliveries declined to major automotive (31.5%) and steel (45.4%). Transition charges for OE and TE that ceased effective January 1, 2009 with the full recovery of related costs and the transition rate reduction for CEI effective June 1, 2009, were offset by PUCO-approved distribution rate increases (see Regulatory Matters – Ohio).

The following table summarizes the price and volume factors contributing to the $153 million decrease in generation revenues in the first six months of 2009 compared to the same period of 2008:

	Increase
Sources of Change in Generation Revenues	(Decrease)
	(In millions)
Retail:
Effect of 6.3% decrease in sales volumes	$	(98	)
Change in prices		67
		(31	)
Wholesale:
Effect of 12.2% decrease in sales volumes		(57	)
Change in prices		(65	)
		(122	)
Net Decrease in Generation Revenues	$	(153	)

The decrease in retail generation sales volumes was primarily due to weakened economic conditions and reduced weather-related usage. Cooling degree days decreased by 23% in the first six months of 2009, while heating degree days increased by 2% compared to the same period last year. The increase in retail generation prices during the first six months of 2009 was due to higher generation rates for JCP&L and Penn under their power procurement processes. Wholesale generation sales decreased principally as a result of JCP&L selling less available power from NUGs due to the termination of a NUG purchase contract in October 2008. The decrease in wholesale prices reflected lower spot market prices in PJM.

14

Transmission revenues increased $3 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the annual updates to their TSC riders. Met-Ed and Penelec defer the difference between revenues from their transmission riders and transmission costs incurred with no material effect on current period earnings (see Regulatory Matters – Pennsylvania).

Expenses –

Total expenses increased by $65 million due to the following:

· Purchased power costs were $138million lower in the first six months of 2009 due to lower volumes, partially offset by higher unit costs and an increase in the amount of NUG costs deferred. The increased unit costs primarily reflected the effect of higher JCP&L costs resulting from its 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	$	163
Change due to decreased volumes		(266	)
		(103	)
Purchases from FES:
Change due to decreased unit costs		(16	)
Change due to increased volumes		37
		21
Increase in NUG costs deferred		(56	)
Net Decrease in Purchased Power Costs	$	(138	)

·   PJM transmission expenses were lower by $81 million, resulting primarily from reduced volumes and congestion costs.

· An increase in other operating expense of $32 million resulted from recognition of economic development and energy efficiency obligations in accordance with the PUCO-approved ESP.

·   A reduction in contractor and material expenses of $21 million, reflecting more costs dedicated to capital projects compared to the prior year, was partially offset by an increase from organizational restructuring costs of $5 million.

· A $63 million increase in the amortization of regulatory assets was due primarily to the ESP-related impairment of CEI’s regulatory assets and PJM transmission cost amortization in the first six months of 2009, partially offset by the cessation of transition cost amortizations for OE and TE.

·   A $198 million decrease in the deferral of new regulatory assets was principally due to the absence of PJM transmission cost deferrals and RCP distribution cost deferrals by the Ohio Companies.

·   Depreciation expense increased $9 million due to property additions since the second quarter of 2008.

·   General taxes decreased $2 million due to lower gross receipts and excise taxes.

Other Expense –

Other expense increased $42 million in the first six months of 2009 compared to 2008. Lower investment income of $21 million resulted primarily from repaid notes receivable from affiliates since the second quarter of 2008. Higher interest expense (net of capitalized interest) of $21million was related to the senior notes issuances of JCP&L and Met-Ed in January 2009 and TE in April 2009.

15

Competitive Energy Services – First Six Months of 2009 Compared to First Six Months of 2008

Net income increased to $431million in the first six months of 2009 compared to $153million in the same period in 2008. The increase in net income includes FGCO's $252 million gain from the sale of 9% of its participation in OVEC ($158 million after tax) and an increase in gross sales margins, partially offset by higher other operating costs.

Revenues –

Total revenues increased $387million in the first six months of 2009 compared to the same period in 2008. This increase primarily resulted from the OVEC sale and higher unit prices on affiliated generation sales to the Ohio Companies and non-affiliated customers, partially offset by lower sales volumes.

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

	Six Months
	Ended June 30				Increase
Revenues by Type of Service	2009		2008		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	174	$	315	$	(141	)
Wholesale		311		298		13
Total Non-Affiliated Generation Sales		485		613		(128	)
Affiliated Generation Sales		1,732		1,480		252
Transmission		41		66		(25	)
Sale of OVEC participation interest		252		-		252
Other		61		25		36
Total Revenues	$	2,571	$	2,184	$	387

The lower retail revenues resulted from the expiration of government aggregation programs in Ohio at the end of 2008 that were supplied by FES, partially offset by increased revenue from both the PJM and MISO markets. The increase in MISO retail sales is primarily the result of the acquisition of new customers and higher unit prices. The increase in PJM retail sales resulted from higher unit prices. As of August 1, 2009, FES has signed new government aggregation contracts with 50 communities that will provide discounted generation prices to approximately 600,000 residential and small commercial customers. The retail sales volumes associated with these new contracts are expected to result in an increased level of retail revenues in the second half of 2009 as compared to results for the period ended June 30, 2009.

Higher non-affiliated wholesale revenues resulted from higher capacity prices in PJM and increased sales volumes and favorable settlements on hedged transactions in MISO, partially offset by decreased sales volumes and spot market prices in PJM. The increased affiliated company generation revenues were due to higher unit prices to the Ohio Companies and increased sales volumes to Met-Ed and Penelec, partially offset by lower sales volumes to the Ohio Companies. The higher unit prices reflected the results of the Ohio Companies' power procurement processes in the first half of 2009 (see Regulatory Matters – Ohio). 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 2009 compared to the first six months of 2008.

In the first quarter of 2009, FES supplied approximately 75% of the Ohio Companies’ power requirements as one of four winning bidders in the Ohio Companies' RFP process. In the second quarter of 2009, FES supplied 100% of the power for the Ohio Companies’ PLR service in April and May 2009, and approximately 56% of the Ohio Companies' supply needs in June 2009. Subsequent to the Ohio Companies’ CBP, FES purchased additional tranches from other winning bidders and effective August 1, 2009, FES will supply 62% of the Ohio Companies’ PLR generation requirements.

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 57.8% decrease in sales volumes	$	(182	)
Change in prices		41
		(141	)
Wholesale:
Effect of 4.1% decrease in sales volumes		(12	)
Change in prices		25
		13
Net Decrease in Non-Affiliated Generation Revenues	$	(128	)

16

	Increase
Source of Change in Affiliated Generation Revenues	(Decrease)
	(In millions)
Ohio Companies:
Effect of 19.2% decrease in sales volumes	$	(218	)
Change in prices		449
		231
Pennsylvania Companies:
Effect of 10.6% increase in sales volumes		37
Change in prices		(16	)
		21
Net Increase in Affiliated Generation Revenues	$	252

Transmission revenues decreased $25 million due primarily to reduced retail loads in MISO. Other revenue increased $36 million primarily due to rental income associated with NGC's acquisition of additional equity interests in the Perry and Beaver Valley Unit 2 leases.

Expenses -

Total expenses decreased $66 million in the first six months of 2009 due to the following factors:

· Purchased power costs decreased $81 million due to lower volume ($103 million), partially offset by higher unit prices ($22 million) that resulted from higher capacity costs.

·   Fuel costs decreased $55 million due to lower generation volumes ($116 million) partially offset by higher unit prices ($61 million). The higher unit prices, which are expected to continue for the remainder of 2009, primarily reflect increased costs for eastern coal.

·   Fossil operating costs decreased $32 million due to a $24 million reduction in contractor and material costs that resulted from reduced maintenance activities and more labor dedicated to capital projects compared to the prior year.

·   Other expense increased $49 million due primarily to increased intersegment billings for leasehold costs from the Ohio Companies.

·   Transmission expense increased $24 million due primarily to increased net congestion and loss expenses in PJM.

· Higher depreciation expense of $20 million was due to NGC's increased ownership interest in Beaver Valley Unit 2 and Perry.

· Nuclear operating costs increased $9 million in the first six months of 2009 due to an additional refueling outage during the 2009 period.

Other Expense –

Total other expense in the first six months of 2009 was $10million lower than the first six months of 2009, primarily due to a decline in interest expense (net of capitalized interest) of $19 million from the repayment of notes payable to affiliates, partially offset by an $8 million decrease in earnings from nuclear decommissioning trust investments resulting from securities impairments.

Ohio Transitional Generation Services – First Six Months of 2009 Compared to First Six Months of 2008

Net income for this segment increased to $45million in the first six months of 2009 from $43 million in the same period of 2008. Higher generation revenues, lower operating expenses and increased deferrals of regulatory assets were partially offset by higher purchased power expenses.

17

Revenues –

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

	Six Months
	Ended June 30
Revenues by Type of Service	2009		2008		Increase (Decrease)
	(In millions)
Generation sales:
Retail	$	1,597	$	1,193	$	404
Wholesale		-		5		(5	)
Total generation sales		1,597		1,198		399
Transmission		181		186		(5	)
Other		2		6		(4	)
Total Revenues	$	1,780	$	1,390	$	390

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
	(In millions)
Retail:
Effect of 4.7% increase in sales volumes	$	56
Change in prices		348
Net Increase in Retail Generation Revenues	$	404

The increase in generation sales volume in the first six months of 2009 was primarily due to reduced customer shopping, reflecting the return of customers to PLR service following the expiration of certain government aggregation programs in Ohio in 2008. This increased sales volume was partially offset by lower sales due to milder weather and economic conditions in the Ohio Companies' service territory. Average prices increased primarily due to an increase in the Ohio Companies' fuel cost recovery riders that were effective from January through May 2009. Effective June 1, 2009, the transmission tariff ended and the recovery of transmission costs is included in the generation rate established under the Ohio Companies' CBP.

Decreased transmission revenue of $5 million resulted from the termination of the transmission tariff and lower MISO revenues partially offset by higher sales volumes. The difference between transmission revenues accrued and transmission costs incurred is deferred, resulting in no material impact to current period earnings.

Expenses -

Purchased power costs were $568million higher due primarily to higher unit costs for power. The factors contributing to the higher costs are summarized in the following table:

Source of Change in Purchased Power	Increase
	(In millions)
Change due to increased unit costs	$	523
Change due to increased volumes		45
		568

The increase in purchased volumes was due to the higher retail generation sales requirements described above. The higher unit costs reflect the results of the Ohio Companies' power supply procurement processes for retail customers during the first six months of 2009 (see Regulatory Matters – Ohio).

Other operating expenses decreased $126 million due to lower MISO transmission expenses ($71 million) and associated company cost reimbursements related to the Ohio Companies' generation leasehold interests. The amortization of regulatory assets increased by $75 million in the first six months of 2009 due primarily to increased MISO transmission cost amortization. The deferral of new regulatory assets increased by $131 million due to CEI’s deferral of purchased power costs as approved by the PUCO.

18

Other – First Six Months of 2009 Compared to First Six Months of 2008

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 $5 million decrease in FirstEnergy's net income in the first six months of 2009 compared to the same period in 2008. The decrease resulted primarily from the absence of the gain on the 2008 sale of telecommunication assets ($19 million, net of taxes), partially offset by the favorable resolution in 2009 of income tax issues relating to prior years ($13 million).

CAPITAL RESOURCES AND LIQUIDITY

FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligations and those of its subsidiaries. FirstEnergy's business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. During 2009 and in subsequent years, FirstEnergy expects to satisfy these requirements with a combination of cash from operations and funds from the capital markets as market conditions warrant. 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, 2009, FirstEnergy's net deficit in working capital (current assets less current liabilities) was principally due to short-term borrowings ($2.4 billion) and the classification of certain variable interest rate PCRBs as currently payable long-term debt. Currently payable long-term debt as of June 30, 2009, included the following (in millions):

Currently Payable Long-term Debt
PCRBs supported by bank LOCs(1)	$	1,553
FGCO and NGC unsecured PCRBs(1)		97
CEI secured notes(2)		150
Met-Ed unsecured notes(3)		100
NGC collateralized lease obligation bonds		44
Sinking fund requirements		40
	$	1,984
(1)  Interest rate mode permits individual debt holders to put the  respective debt back to the issuer prior to maturity. (2)  Mature in November 2009. (3)  Mature in March 2010.

Short-Term Borrowings

FirstEnergy had approximately $2.4 billion of short-term borrowings as of June 30, 2009 and December 31, 2008. FirstEnergy, along with certain of its subsidiaries, have access to $2.75 billion of short-term financing under a revolving credit facility that expires in August 2012. A total of 25 banks participate in the facility, with no one bank having more than 7.3% of the total commitment. As of July 30, 2009, FirstEnergy had $420 million of bank credit facilities in addition to the $2.75 billion revolving credit facility. Also, an aggregate of $550 million of accounts receivable financing facilities through the Ohio and Pennsylvania Companies may be accessed to meet working capital requirements and for other general corporate purposes. FirstEnergy's available liquidity as of July 30, 2009, is summarized in the following table:

Company	Type	Maturity	Commitment		Available Liquidity as of July 30, 2009
			(In millions)
FirstEnergy(1)	Revolving	Aug. 2012	$	2,750	$	273
FirstEnergy and FES	Bank lines	Various(2)		120		20
FGCO	Term loan	Oct. 2009(3)		300		300
Ohio and Pennsylvania Companies	Receivables financing	Various(4)		550		451
		Subtotal	$	3,720	$	1,044
		Cash		-		921
		Total	$	3,720	$	1,965
(1)FirstEnergy Corp. and subsidiary borrowers. (2)$100 million expires March 31, 2011; $20 million uncommitted line of credit has no expiration date. (3)Drawn amounts are payable within 30 days and may not be re-borrowed. (4)$180 million expires December 18, 2009; $370 million expires February 22, 2010.

19

Revolving Credit Facility

FirstEnergy has the capability to request an increase in the total commitments available under the $2.75 billion revolving credit facility (included in the borrowing capability table above) up to a maximum of $3.25 billion, subject to the discretion of each lender to provide additional commitments. 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.

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 as of June 30, 2009:

	Revolving			Regulatory and
	Credit Facility			Other Short-Term
Borrower	Sub-Limit			Debt Limitations
	(In millions)
FirstEnergy	$	2,750		$	-	(1)
FES		1,000			-	(1)
OE		500			500
Penn		50			39	(2)
CEI		250	(3)		500
TE		250	(3)		500
JCP&L		425			428	(2)
Met-Ed		250			300	(2)
Penelec		250			300	(2)
ATSI		-	(4)		50
(1)No regulatory approvals, statutory or charter limitations applicable. (2)Excluding amounts which may be borrowed under the regulated companies' money pool. (3)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.  (4)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.

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, 2009, FirstEnergy's and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:

Borrower
FirstEnergy(1)	60.7	%
FES	53.7	%
OE	47.8	%
Penn	28.2	%
CEI	54.4	%
TE	59.7	%
JCP&L	37.2	%
Met-Ed	49.8	%
Penelec	50.9	%

(1)As of June 30, 2009, FirstEnergy could issue additional debt of approximately

 $3.2 billion, or recognize a reduction in equity of approximately $1.7 billion, and

 remain within the limitations of the financial covenants required by its revolving

 credit facility.

20

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

FirstEnergy Money Pools

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 2009 was 0.86% for the regulated companies' money pool and 1.00% for the unregulated companies' money pool.

Pollution Control Revenue Bonds

As of June 30, 2009, FirstEnergy's currently payable long-term debt included approximately $1.6 billion (FES - $1.5 billion, Met-Ed - $29 million and Penelec - $45 million) of variable interest rate PCRBs, the bondholders of which are entitled to the benefit of irrevocable direct pay bank LOCs. The interest rates on the PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory purchase prior to maturity with the purchase price payable from remarketing proceeds or, if the PCRBs are not successfully remarketed, by drawings on the irrevocable direct pay LOCs. The subsidiary obligor is required to reimburse the applicable LOC bank for any such drawings or, if the LOC bank fails to honor its LOC for any reason, must itself pay the purchase price.

The LOCs for FirstEnergy variable interest rate PCRBs were issued by the following banks:

	Aggregate LOC			Reimbursements of
LOC Bank	Amount(3)		LOC Termination Date	LOC Draws Due
	(In millions)
CitiBank N.A.	$	166	June 2014	June 2014
The Bank of Nova Scotia	255		Beginning June 2010	Shorter of 6 months or LOC termination date
The Royal Bank of Scotland	131		June 2012	6 months
KeyBank(1)	266		June 2010	6 months
Wachovia Bank	153		March 2014	March 2014
Barclays Bank(2)	528		Beginning December 2010	30 days
PNC Bank		70	Beginning November 2010	180 days
Total	$	1,569
(1)Supported by four participating banks, with the LOC bank having 62% of the total commitment. (2)Supported by 18 participating banks, with no one bank having more than 14% of the total commitment. (3)Includes approximately $16 million of applicable interest coverage.

In February 2009, holders of approximately $434 million principal of LOC-supported PCRBs of OE and NGC were notified that the applicable Wachovia Bank LOCs were to expire on March 18, 2009. As a result, these PCRBs were subject to mandatory purchase at a price equal to the principal amount, plus accrued and unpaid interest, which OE and NGC funded through short-term borrowings. In March 2009, FGCO remarketed $100 million of those PCRBs, which were previously held by OE. During the second quarter of 2009, NGC remarketed the remaining $334 million of PCRBs, of which $170 million was remarketed in fixed interest rate modes and secured by FMBs, thereby eliminating the need for third-party credit support. During the second quarter of 2009, FGCO remarketed approximately $248 million of PCRBs supported by LOCs set to expire in June 2009. These PCRBs were remarketed in fixed interest rate modes and secured by FMBs, thereby eliminating the need for third-party credit support. Also, in June 2009, FGCO and NGC delivered FMBs to certain LOC banks listed above in connection with amendments to existing letter of credit and reimbursement agreements supporting 12 other series of PCRBs as described below and pledged FMBs to the applicable trustee under six separate series of PCRBs.

21

Long-Term Debt Capacity

As of June 30, 2009, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.3 billion of additional FMBs on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMBs by the Ohio Companies 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 FMBs) supporting pollution control notes or similar obligations, or as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE and CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $167 million and $175 million, respectively, as of June 30, 2009. In April 2009, TE issued $300 million of new senior secured notes backed by FMBs. Concurrently with that issuance, and in order to satisfy the limitation on secured debt under its senior note indenture, TE issued an additional $300 million of FMBs to secure $300 million of its outstanding unsecured senior notes originally issued in November 2006. As a result, the provisions for TE to incur additional secured debt do not apply.

Based upon FGCO's FMB indenture, net earnings and available bondable property additions as of June 30, 2009, FGCO had the capability to issue $2.2 billion of additional FMBs under the terms of that indenture. On June 16, 2009, FGCO issued a total of approximately $395.9 million in principal amount of FMBs, of which $247.7 million related to three new refunding series of PCRBs and approximately $148.2 million related to amendments to existing letter of credit and reimbursement agreements supporting two other series of PCRBs. On June 30, 2009, FGCO issued a total of approximately $52.1 million in principal amount of FMBs related to three existing series of PCRBs.

In June 2009, a new FMB indenture was put in place for NGC. Based upon NGC’s FMB indenture, net earnings and available bondable property additions, NGC had the capability to issue $264 million of additional FMBs as of June 30, 2009. On June 16, 2009, NGC issued a total of approximately $487.5 million in principal amount of FMBs, of which $107.5 million related to one new refunding series of PCRBs and approximately $380 million related to amendments to existing letter of credit and reimbursement agreements supporting seven other series of PCRBs. In addition, on June 16, 2009, NGC issued an FMB in a principal amount of up to $500 million in connection with its guaranty of FES’ obligations to post and maintain collateral under the Power Supply Agreement entered into by FES with the Ohio Companies as a result of the May 13-14, 2009 CBP auction. On June 30, 2009, NGC issued a total of approximately $273.3 million in principal amount of FMBs, of which approximately $92 million related to three existing series of PCRBs and approximately $181.3 million related to amendments to existing letter of credit and reimbursement agreements supporting three other series of PCRBs.

Met-Ed and Penelec had the capability to issue secured debt of approximately $428 million and $310 million, respectively, under provisions of their senior note indentures as of June 30, 2009.

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 Utilities' securities ratings as of June 30, 2009. On June 17, 2009, Moody's affirmed FirstEnergy's Baa3 and FES' Baa2 credit ratings. On July 9, 2009, S&P affirmed its ratings on FirstEnergy and its subsidiaries. S&P's and Moody's outlook for FirstEnergy and its subsidiaries remains "stable."

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

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On September 22, 2008, FirstEnergy, along with the Shelf Registrants, filed an automatically effective shelf registration statement with the SEC for an unspecified number and amount of securities to be offered thereon. The shelf registration provides FirstEnergy the flexibility to issue and sell various types of securities, including common stock, preferred stock, debt securities, warrants, share purchase contracts, and share purchase units. The Shelf Registrants have utilized, and may in the future utilize, the shelf registration statement to offer and sell unsecured and, in some cases, secured debt securities. On July 29, 2009, FES registered its common stock pursuant to Section 12(g) of the Securities Exchange Act of 1934.

Changes in Cash Position

As of June 30, 2009, FirstEnergy had $900 million in cash and cash equivalents compared to $545 million as of December 31, 2008. Cash and cash equivalents consist of unrestricted, highly liquid instruments with an original or remaining maturity of three months or less. As of June 30, 2009, approximately $825 million of cash and cash equivalents represented temporary overnight deposits.

During the first six months of 2009, FirstEnergy received $453 million of cash from dividends and equity repurchases 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 FirstEnergy’s subsidiaries. In addition to paying dividends from retained earnings, each of FirstEnergy’s electric utility subsidiaries has authorization from the FERC to pay cash dividends from paid-in capital accounts, as long as the subsidiary’s debt to total capitalization ratio (without consideration of retained earnings) remains below 65%. CEI and TE are the only utility subsidiaries currently precluded from that action.

Cash Flows From Operating Activities

FirstEnergy's consolidated net cash from operating activities is provided primarily by its competitive energy services and energy delivery services businesses (see Results of Operations above). Net cash provided from operating activities was $1.1 billion and $319 million in the first six months of 2009 and 2008, respectively, as summarized in the following table:

	Six Months
	Ended June 30
Operating Cash Flows	2009			2008
	(In millions)
Net income	$	523		$	540
Non-cash charges		719			435
Working capital and other		(140	)		(656	)
	$	1,102		$	319

Net cash provided from operating activities increased by $783 million in the first six months of 2009 compared to the first six months of 2008 primarily due to a $284 million increase in non-cash charges and a $516 million increase from working capital and other changes, partially offset by a $17 million decrease in net income (see Results of Operations above). The increase in non-cash charges is primarily due to higher net amortization of regulatory assets, including CEI’s $216 million regulatory asset impairment, and changes in accrued compensation and retirement benefits. The change in accrued compensation and retirement benefits resulted from higher non-cash retirement benefit expenses recognized in the first six months of 2009. The changes in working capital and other primarily resulted from lower net tax payments of $278 million, a $70 million decrease in stock-based compensation payments and an increase in other accrued expenses principally associated with the implementation of the Ohio Companies’ Amended ESP.

Cash Flows From Financing Activities

In the first six months of 2009, cash provided from financing activities was $426 million compared to $1.2 billion in the first six months of 2008. The decrease was primarily due to reduced short-term borrowings, partially offset by long-term debt issuances in the first six months of 2009. The following table summarizes security issuances (net of any discounts) and redemptions.

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	Six Months
	Ended June 30
Securities Issued or Redeemed	2009		2008
	(In millions)
New issues
First mortgage bonds	$	100	$	-
Pollution control notes		682		529
Senior secured notes		297		-
Unsecured notes		600		20
	$	1,679	$	549
Redemptions
First mortgage bonds	$	-	$	1
Pollution control notes		682		529
Senior secured notes		46		15
Unsecured notes		153		175
	$	881	$	720
Short-term borrowings, net	$	-	$	1,705

The following table summarizes new debt issuances (excluding PCRB issuances and refinancings) during 2009.

Issuing Company	Issue Date	Principal (in millions)	Type	Maturity	Use of Proceeds
Met-Ed*	01/20/2009	$300	7.70% Senior Notes	2019	Repay short-term borrowings
JCP&L*	01/27/2009	$300	7.35% Senior Notes	2019	Repay short-term borrowings, fund capital expenditures and other general purposes
TE*	04/24/2009	$300	7.25% Senior Secured Notes	2020	Repay short-term borrowings, fund capital expenditures and other general purposes
Penn	06/30/2009	$100	6.09% FMB	2022	Fund capital expenditures and repurchase equity from OE
* Issuance was sold off the shelf registration statement referenced above.

Cash Flows From Investing Activities

Net cash flows used in investing activities resulted primarily from property additions. Additions for the energy delivery services segment primarily represent 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, 2009 and 2008 by business segment:

Summary of Cash Flows	Property
Provided from (Used for) Investing Activities	Additions			Investments			Other			Total
Sources (Uses)	(In millions)
Six Months Ended June 30, 2009
Energy delivery services	$	(343	)	$	48		$	(23	)	$	(318	)
Competitive energy services		(669	)		2			(22	)		(689	)
Other		(119	)		(7	)		(3	)		(129	)
Inter-Segment reconciling items		(12	)		(25	)		-			(37	)
Total	$	(1,143	)	$	18		$	(48	)	$	(1,173	)
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	)

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Net cash used for investing activities in the first six months of 2009 decreased by $432 million compared to the first six months of 2008. The decrease was principally due to a $474 million decrease in property additions, which reflects lower AQC system expenditures and the absence in 2009 of the purchase of certain lessor equity interests in Beaver Valley Unit 2 and Perry, and the purchase of a partially-completed generating plant in Fremont, Ohio.  The decrease in property additions was partially offset by the absence in 2009 of cash proceeds from the sale of telecommunication assets in the first quarter of 2008.

During the second half of 2009, capital requirements for property additions and capital leases are expected to be approximately $773 million, including approximately $176 million for nuclear fuel. FirstEnergy has additional requirements of approximately $177 million for maturing long-term debt during the remainder of 2009. 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 2009-2013 is expected to be approximately $7.9 billion (excluding nuclear fuel), of which approximately $1.6 billion applies to 2009. Investments for additional nuclear fuel during the 2009-2013 period are estimated to be approximately $1.3 billion, of which about $337 million applies to 2009. During the same period, FirstEnergy's nuclear fuel investments are expected to be reduced by approximately $1.0 billion and $131 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, 2009, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.6 billion, as summarized below:

	Maximum
Guarantees and Other Assurances	Exposure
	(In millions)
FirstEnergy Guarantees on Behalf of its Subsidiaries
Energy and Energy-Related Contracts (1)	$	427
LOC (long-term debt) – interest coverage (2)		6
FirstEnergy guarantee of OVEC obligations		300
Other (3)		600
		1,333
Subsidiaries’ Guarantees
Energy and Energy-Related Contracts		54
LOC (long-term debt) – interest coverage (2)		6
FES’ guarantee of NGC’s nuclear property insurance		77
FES’ guarantee of FGCO’s sale and leaseback obligations		2,502
		2,639
Surety Bonds		108
LOC (long-term debt) – interest coverage (2)		4
LOC (non-debt) (4)(5)		501
		613
Total Guarantees and Other Assurances	$	4,585

(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 $1.6 billion is reflected in currently payable long-term debt on FirstEnergy’s consolidated balance sheets.

(3) Includes guarantees of $80 million for nuclear decommissioning funding (see Nuclear Plant Matters below) assurances and $161 million supporting OE’s sale and leaseback arrangement. Also includes $300 million for a Credit Suisse credit facility for FGCO that is guaranteed by both FirstEnergy and FES.

(4) Includes $161 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facility.

(5) Includes approximately $206 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 by OE.

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FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge 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 its 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 FirstEnergy assets. FirstEnergy believes 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 to below investment grade or a “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of June 30, 2009, FirstEnergy’s maximum exposure under these collateral provisions was $601 million as shown below:

Collateral Provisions	FES		Utilities		Total
	(In millions)
Credit rating downgrade to   below investment grade	$	315	$	110	$	425
Acceleration of payment or   funding obligation		80		55		135
Material adverse event		41		-		41
Total	$	436	$	165	$	601

Stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase the total potential amount to $700 million, consisting of $49 million due to “material adverse event” contractual clauses and $651 million due to a below investment grade credit rating.

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.

In addition to guarantees and surety bonds, FES’ contracts, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions which require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ power portfolio as of June 30, 2009, and forward prices as of that date, FES had $179 million of outstanding collateral payments. Under a hypothetical adverse change in forward prices (15% decrease in the first 12 months and 20% decrease thereafter in prices), FES would be required to post an additional $73 million. Depending on the volume of forward contracts entered and future price movements, FES could be required to post significantly higher amounts for margining.

In connection with FES’ obligations to post and maintain collateral under the two-year PSA entered into by FES and the Ohio Companies following the CBP auction on May 13-14, 2009, NGC entered into a Surplus Margin Guaranty in the amount of approximately $500 million, dated as of June 16, 2009, in favor of the Ohio Companies.

FES’ debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC, pursuant to guarantees entered into on March 26, 2007. Similar guarantees were entered into on that date pursuant to which FES guaranteed the debt obligations of each of FGCO and NGC.  Accordingly, present and future holders of indebtedness of FES, FGCO and NGC will have claims against each of FES, FGCO and NGC regardless of whether their primary obligor is FES, FGCO or NGC.

OFF-BALANCE SHEET ARRANGEMENTS

FES and the Ohio Companies have obligations that are not included on their Consolidated Balance Sheets related to sale and leaseback arrangements involving the Bruce Mansfield Plant, Perry Unit 1 and Beaver Valley Unit 2, which are satisfied through operating lease payments. The total present value of these sale and leaseback operating lease commitments, net of trust investments is $1.7 billion as of June 30, 2009.

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.

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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 or regulatory liability for below-market costs. The change in the fair value of commodity derivative contracts related to energy production during the three months and six months ended June 30, 2009 are summarized in the following table:

	Three Months									Six Months
	Ended June 30, 2009									Ended June 30, 2009
Fair Value 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	$	(457	)	$	(29	)	$	(486	)	$	(304	)	$	(41	)	$	(345	)
Additions/change in value of existing contracts		(154	)		8			(146	)		(381	)		(2	)		(383	)
Settled contracts		96			7			103			170			29			199
Outstanding net liability at end of period (1)	$	(515	)	$	(14	)	$	(529	)	$	(515	)	$	(14	)	$	(529	)
Non-commodity Net Liabilities at End of Period:
Interest rate swaps (2)		-			(3	)		(3	)		-			(3	)		(3	)
Net Liabilities - Derivative Contracts at End of Period	$	(515	)	$	(17	)	$	(532	)	$	(515	)	$	(17	)	$	(532	)
Impact of Changes in Commodity Derivative Contracts(3)
Income statement effects (pre-tax)	$	2		$	-		$	2		$	3		$	-		$	3
Balance sheet effects:
Other comprehensive income (pre-tax)	$	-		$	15		$	15		$	-		$	27		$	27
Regulatory assets (net)	$	60		$	-		$	60		$	214		$	-		$	214

(1) Includes $517 million in non-hedge commodity derivative contracts (primarily with NUGs) which are offset by a regulatory asset.

(2) Interest rate swaps are treated as cash flow or fair value hedges.

(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, 2009 as follows:

Balance Sheet Classification	Non-Hedge			Hedge			Total
	(In millions)
Current-
Other assets	$	2		$	21		$	23
Other liabilities		-			(31	)		(31	)
Non-Current-
Other deferred charges		233			-			233
Other non-current liabilities		(750	)		(7	)		(757	)
Net liabilities	$	(515	)	$	(17	)	$	(532	)

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 to the consolidated financial statements). Sources of information for the valuation of commodity derivative contracts as of June 30, 2009 are summarized by year in the following table:

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Source of Information
- Fair Value by Contract Year	2009(1)			2010			2011			2012			2013			Thereafter		Total
	(In millions)
Prices actively quoted(2)	$	(7	)	$	(11	)	$	-		$	-		$	-		$	-	$	(18	)
Other external sources(3)		(147	)		(252	)		(204	)		(120	)		-			-		(723	)
Prices based on models		-			-			-			-			(1	)		213		212
Total(4)	$	(154	)	$	(263	)	$	(204	)	$	(120	)	$	(1	)	$	213	$	(529	)

(1)     For the last two quarters of 2009.

(2)     Represents exchange traded NYMEX futures and options.

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

(4) Includes $517 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset.

FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on its derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of June 30, 2009. Based on derivative contracts held as of June 30, 2009, an adverse 10% change in commodity prices would decrease net income by approximately $4 million during the next 12 months.

Forward Starting Swap Agreements - Cash Flow Hedges

FirstEnergy utilizes forward starting swap agreements 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 2009 and 2010, 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 2009, FirstEnergy terminated forward swaps with an aggregate notional value of $100million. FirstEnergy paid $1.3 million in cash related to the terminations, $0.3 million of which was deemed ineffective and recognized in current period earnings. The remaining effective portion ($1 million) will be recognized over the terms of the associated future debt. As of June 30, 2009, FirstEnergy had outstanding forward swaps with an aggregate notional amount of $200 million and an aggregate fair value of $(3) million.

	June 30, 2009							December 31, 2008
	Notional		Maturity		Fair			Notional		Maturity		Fair
Forward Starting Swaps	Amount		Date		Value			Amount		Date		Value
	(In millions)
Cash flow hedges	$	100		2009	$	(1	)	$	100		2009	$	(2	)
		100		2010		(2	)		100		2010		(2	)
		-		2019		-			100		2019		1
	$	200			$	(3	)	$	300			$	(3	)

Equity Price Risk

FirstEnergy provides a noncontributory qualified defined benefit pension plan that covers substantially all of its employees and non-qualified pension plans that cover certain employees. The plan provides defined benefits based on years of service and compensation levels. FirstEnergy also provides health care benefits, which include certain employee contributions, deductibles, and co-payments, upon retirement to employees hired prior to January 1, 2005, their dependents, and under certain circumstances, their survivors. The benefit plan assets and obligations are remeasured annually using a December 31 measurement date. FirstEnergy’s other postretirement benefits plans were remeasured as of May 31, 2009 as a result of a plan amendment announced on June 2, 2009, which reduces future health care coverage subsidies paid by FirstEnergy on behalf of plan participants. The remeasurement and plan amendment will result in a $48 million reduction in FirstEnergy’s net postretirement benefit cost (including amounts capitalized) for the remainder of 2009, including a $7 million reduction that is applicable to the second quarter of 2009 (see Note 5). Reductions in plan assets from investment losses during 2008 resulted in a decrease to the plans' funded status of $1.7 billion and an after-tax decrease to common stockholders' equity of $1.2 billion. As of December 31, 2008, the pension plan was underfunded and FirstEnergy currently estimates that additional cash contributions will be required in 2011 for the 2010 plan year. The overall actual investment result during 2008 was a loss of 23.8% compared to an assumed 9% positive return. Based on assumed 7-7.5% discount rates, FirstEnergy's pre-tax net periodic pension and OPEB expense was $38 million in the second quarter of 2009.

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Nuclear decommissioning trust funds have been established to satisfy NGC's and the Utilities' nuclear decommissioning obligations. As of June 30, 2009, approximately 34% of the funds were invested in equity securities and 66% were invested in fixed income securities, with limitations related to concentration and investment grade ratings. The equity securities are carried at their market value of approximately $588 million as of June 30, 2009. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $59 million reduction in fair value as of June 30, 2009. The decommissioning trusts of JCP&L and the Pennsylvania Companies are subject to regulatory accounting, with unrealized gains and losses recorded as regulatory assets or liabilities, since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers. NGC, OE and TE recognize in earnings the unrealized losses on available-for-sale securities held in their nuclear decommissioning trusts based on the guidance for other-than-temporary impairments provided in SFAS 115, FSP SFAS 115-1 and SFAS 124-1. On June 18, 2009, the NRC informed FENOC that its review tentatively concluded that a shortfall ($147.5 million net present value) existed in the value of the decommissioning trust fund for Beaver Valley Unit 1. Renewal of the operating license for Beaver Valley Unit 1 (see Nuclear Plant Matters) would mitigate the estimated shortfall in the unit’s nuclear decommissioning funding status. FENOC continues to communicate with the NRC regarding future actions to provide reasonable assurance for decommissioning funding. Such actions may include additional parental guarantees or contributions to those funds.

CREDIT RISK

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

FirstEnergy maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As of June 30, 2009, the largest credit concentration was with JP Morgan, which is currently rated investment grade, representing 9.4% of FirstEnergy's total approved credit risk.

OUTLOOK

State Regulatory Matters

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

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

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

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

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

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

· requiring corporate separation of regulated and unregulated business activities.

The Utilities 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 $158 million as of June 30, 2009 (JCP&L - $48 million, Met-Ed - $95 million and Penelec - $15 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 and Penelec. The following table discloses net regulatory assets by company:

29

	June 30,		December 31,		Increase
Regulatory Assets	2009		2008		(Decrease)
	(In millions)
OE	$	514	$	575	$	(61	)
CEI		628		784		(156	)
TE		91		109		(18	)
JCP&L		1,055		1,228		(173	)
Met-Ed		497		413		84
Penelec*		10		-		10
ATSI		24		31		(7	)
Total	$	2,819	$	3,140	$	(321	)

* Penelec had net regulatory liabilities of approximately $137 million as of December 31, 2008. These net regulatory liabilities are   included in Other Non-current Liabilities on the Consolidated Balance Sheets.

Regulatory assets by source are as follows:

	June 30,			December 31,			Increase
Regulatory Assets By Source	2009			2008			(Decrease)
	(In millions)
Regulatory transition costs	$	1,278		$	1,452		$	(174	)
Customer shopping incentives		218			420			(202	)
Customer receivables for future income taxes		332			245			87
Loss on reacquired debt		52			51			1
Employee postretirement benefits		27			31			(4	)
Nuclear decommissioning, decontamination
and spent fuel disposal costs		(115	)		(57	)		(58	)
Asset removal costs		(226	)		(215	)		(11	)
MISO/PJM transmission costs		279			389			(110	)
Purchased power costs		360			214			146
Distribution costs		482			475			7
Other		132			135			(3	)
Total	$	2,819		$	3,140		$	(321	)

Reliability Initiatives

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 Utilities 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 MISO region and found it to be in full compliance with all audited reliability standards. Similarly, in October 2008, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the PJM region and found it to be in full compliance with all audited reliability standards.

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On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations, with customers in the affected area losing power. Power was restored to most customers within a few hours and to all customers within eleven hours. On December 16, 2008, JCP&L provided preliminary information about the event to certain regulatory agencies, including the NERC. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. The initial phase of the investigation requires JCP&L to respond to the NERC’s request for factual data about the outage. JCP&L submitted its written response on May 1, 2009. The NERC conducted on site interviews with personnel involved in responding to the event on June 16-17, 2009. On July 7, 2009, the NERC issued additional questions regarding the event and JCP&L is required to reply by August 7, 2009. JCP&L is not able at this time to predict what actions, if any, that the NERC may take based on the data submittal or interview results.

On June 5, 2009, FirstEnergy self-reported to ReliabilityFirst a potential violation of NERC Standard PRC-005 resulting from its inability to validate maintenance records for 20 protection system relays in JCP&L’s and Penelec’s transmission systems. These potential violations were discovered during a comprehensive field review of all FirstEnergy substations to verify equipment and maintenance database accuracy. FirstEnergy has completed all mitigation actions, including calibrations and maintenance records for the relays. ReliabilityFirst issued an Initial Notice of Alleged Violation on June 22, 2009. FirstEnergy is not able at this time to predict what actions or penalties, if any, that ReliabilityFirst will propose for this self-report of violation.

Ohio

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. On January 21, 2009, the PUCO granted the Ohio Companies’ application to increase electric distribution rates by $136.6 million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million). These increases went into effect for OE and TE on January 23, 2009, and for CEI on May 1, 2009. Applications for rehearing of this order were filed by the Ohio Companies and one other party on February 20, 2009. The PUCO granted these applications for rehearing on March 18, 2009 for the purpose of further consideration. The PUCO has not yet issued a substantive Entry on Rehearing.

SB221, which became effective on July 31, 2008, required all electric utilities to file an ESP, and permitted the filing of an MRO. On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and a separate MRO. The PUCO denied the MRO application; however, the PUCO later granted the Ohio Companies’ application for rehearing for the purpose of further consideration of the matter, which is still pending. The ESP proposed to phase in new generation rates for customers beginning in 2009 for up to a three-year period and resolve the Ohio Companies’ collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. In response to the PUCO’s December 19, 2008 order, which significantly modified and approved the ESP as modified, the Ohio Companies notified the PUCO that they were withdrawing and terminating the ESP application in addition to continuing their current rate plan in effect as allowed by the terms of SB221. On December 31, 2008, the Ohio Companies conducted a CBP for the procurement of electric generation for retail customers from January 5, 2009 through March 31, 2009. The average winning bid price was equivalent to a retail rate of 6.98 cents per KWH. The power supply obtained through this process provided generation service to the Ohio Companies’ retail customers who chose not to shop with alternative suppliers. On January 9, 2009, the Ohio Companies requested the implementation of a new fuel rider to recover the costs resulting from the December 31, 2008 CBP. The PUCO ultimately approved the Ohio Companies’ request for a new fuel rider to recover increased costs resulting from the CBP but denied OE’s and TE’s request to continue collecting RTC and denied the request to allow the Ohio Companies to continue collections pursuant to the two existing fuel riders. The new fuel rider recovered the increased purchased power costs for OE and TE, and recovered a portion of those costs for CEI, with the remainder being deferred for future recovery.

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On January 29, 2009, the PUCO ordered its Staff to develop a proposal to establish an ESP for the Ohio Companies. On February 19, 2009, the Ohio Companies filed an Amended ESP application, including an attached Stipulation and Recommendation that was signed by the Ohio Companies, the Staff of the PUCO, and many of the intervening parties. Specifically, the Amended ESP provided that generation would be provided by FES at the average wholesale rate of the CBP process described above for April and May 2009 to the Ohio Companies for their non-shopping customers; for the period of June 1, 2009 through May 31, 2011, retail generation prices would be based upon the outcome of a descending clock CBP on a slice-of-system basis. The Amended ESP further provided that the Ohio Companies will not seek a base distribution rate increase, subject to certain exceptions, with an effective date of such increase before January 1, 2012, that CEI would agree to write-off approximately $216 million of its Extended RTC balance, and that the Ohio Companies would collect a delivery service improvement rider at an overall average rate of $.002 per KWH for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addressed a number of other issues, including but not limited to, rate design for various customer classes, and resolution of the prudence review and the collection of deferred costs that were approved in prior proceedings. On February 26, 2009, the Ohio Companies filed a Supplemental Stipulation, which was signed or not opposed by virtually all of the parties to the proceeding, that supplemented and modified certain provisions of the February 19, 2009 Stipulation and Recommendation. Specifically, the Supplemental Stipulation modified the provision relating to governmental aggregation and the Generation Service Uncollectible Rider, provided further detail on the allocation of the economic development funding contained in the Stipulation and Recommendation, and proposed additional provisions related to the collaborative process for the development of energy efficiency programs, among other provisions. The PUCO adopted and approved certain aspects of the Stipulation and Recommendation on March 4, 2009, and adopted and approved the remainder of the Stipulation and Recommendation and Supplemental Stipulation without modification on March 25, 2009. Certain aspects of the Stipulation and Recommendation and Supplemental Stipulation took effect on April 1, 2009 while the remaining provisions took effect on June 1, 2009.

On July 27, 2009, the Ohio Companies filed applications with the PUCO to recover three different categories of deferred distribution costs on an accelerated basis. In the Ohio Companies' Amended ESP, the PUCO approved the recovery of these deferrals, with collection originally set to begin in January 2011 and to continue over a 5 or 25 year period. The principal amount plus carrying charges through August 31, 2009 for these deferrals is a total of $298.4 million. If the applications are approved, recovery of this amount, together with carrying charges calculated as approved in the Amended ESP, will be collected in the 18 non-summer months from September 2009 through May 2011, subject to reconciliation until fully collected, with $165 million of the above amount being recovered from residential customers, and $133.4 million being recovered from non-residential customers. Pursuant to the applications, customers would pay significantly less over the life of the recovery of the deferral through the reduction in carrying charges as compared to the expected recovery under the previously approved recovery mechanism.

The Ohio Companies are presently involved in collaborative efforts related to energy efficiency and a competitive bidding process, together with other implementation efforts arising out of the Supplemental Stipulation. The CBP auction occurred on May 13-14, 2009, and resulted in a weighted average wholesale price for generation and transmission of 6.15 cents per KWH. The bid was for a single, two-year product for the service period from June 1, 2009 through May 31, 2011. FES participated in the auction, winning 51% of the tranches (one tranche equals one percent of the load supply). Subsequent to the signing of the wholesale contracts, two winning bidders reached separate agreements with FES to assign a total of 11 tranches to FES for various periods. In addition, FES has separately contracted with numerous communities to provide retail generation service through governmental aggregation programs.

SB221 also requires electric distribution utilities to implement energy efficiency programs that achieve a total annual energy savings equivalent of approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013. Utilities are also required to reduce peak demand in 2009 by 1%, with an additional seventy-five hundredths of one percent reduction each year thereafter through 2018. Additionally, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they serve in 2009. FirstEnergy has efforts underway to address compliance with these requirements. Costs associated with compliance are recoverable from customers.

On June 17, 2009, the PUCO modified rules that implement the alternative energy portfolio standards created by SB221, including the incorporation of energy efficiency requirements, long-term forecast and greenhouse gas reporting and CO2 control planning. The PUCO filed the rules with the Joint Committee on Agency Rule Review on July 7, 2009, after which begins a 65-day review period. The Ohio Companies and one other party filed applications for rehearing on the rules with the PUCO on July 17, 2009.

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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. 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. 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. See FERC Matters below for a description of the Third Restated Partial Requirements Agreement, executed by the parties on October 31, 2008, that limits the amount of energy and capacity FES must supply to Met-Ed and Penelec. In the event of a third party supplier default, the increased costs to Met-Ed and Penelec could be material.

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 those filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing Met-Ed 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. Hearings and briefing for both Met-Ed and Penelec have concluded and the companies are awaiting a Recommended Decision from the ALJ. The TSCs included a component from under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for 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 May 28, 2009, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the period June 1, 2009 through May 31, 2010, as required in connection with the PPUC’s January 2007 rate order. For Penelec’s customers the new TSC resulted in an approximate 1% decrease in monthly bills, reflecting projected PJM transmission costs as well as a reconciliation for costs already incurred. The TSC for Met-Ed’s customers increased to recover the additional PJM charges paid by Met-Ed in the previous year and to reflect updated projected costs. In order to gradually transition customers to the higher rate, the PPUC approved Met-Ed’s proposal to continue to recover the prior period deferrals allowed in the PPUC’s May 2008 Order and defer $57.5 million of projected costs to a future TSC to be fully recovered by December 31, 2010. Under this proposal, monthly bills for Met-Ed’s customers will increase approximately 9.4% for the period June 2009 through May 2010.

On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law which became effective on November 14, 2008 as Act 129 of 2008. Act 129 addresses issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Major provisions of the legislation include:

·   power acquired by utilities to serve customers after rate caps expire will be procured through a competitive procurement process that must include a prudent mix of long-term and short-term contracts and spot market purchases;

·   the competitive procurement process must be approved by the PPUC and may include auctions, RFPs, and/or bilateral agreements;

·   utilities must provide for the installation of smart meter technology within 15 years;

·   utilities must reduce peak demand by  a minimum of 4.5% by May 31, 2013;

·   utilities must reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively; and

·   the definition of Alternative Energy was expanded to include additional types of hydroelectric and biomass facilities.

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Act 129 requires utilities to file with the PPUC an energy efficiency and peak load reduction plan by July 1, 2009, and a smart meter procurement and installation plan by August 14, 2009. On January 15, 2009, in compliance with Act 129, the PPUC issued its proposed guidelines for the filing of utilities’ energy efficiency and peak load reduction plans. On June 18, 2009, the PPUC issued its guidelines related to Smart Meter deployment. On July 1, 2009, Met-Ed, Penelec, and Penn filed Energy Efficiency and Conservation Plans with the PPUC in accordance with Act 129.

Legislation addressing rate mitigation and the expiration of rate caps was not enacted in 2008; however, several bills addressing these issues have been introduced in the current legislative session, which began in January 2009. The final form and impact of such legislation is uncertain.

On February 20, 2009, Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The companies’ plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposes a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. Met-Ed and Penelec have requested PPUC approval of their plan by November 2009.

On February 26, 2009, the PPUC approved a Voluntary Prepayment Plan requested by Met-Ed and Penelec that provides an opportunity for residential and small commercial customers to prepay an amount on their monthly electric bills during 2009 and 2010. Customer prepayments earn interest at 7.5% and will be used to reduce electricity charges in 2011 and 2012.

On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance filing to the PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the residential class with a corresponding increase in the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $51 million), overall rates would remain unchanged. On July 30, 2009, the PPUC entered an order approving the 5-year NUG Statement, approving the reduction of the CTC, and directing Met-Ed and Penelec to file a tariff supplement implementing this change. On July 31, 2009, Met-Ed and Penelec filed tariff supplements decreasing the CTC rate in compliance with the July 30, 2009 order, and increasing the generation rate in compliance with the companies’ Restructuring Orders of 1998. Met-Ed and Penelec are awaiting PPUC action on the July 31, 2009 filings.

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, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of June 30, 2009, the accumulated deferred cost balance totaled approximately $149 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 DPA 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 March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009. This matter is currently pending before the NJBPU.

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.

The EMP was issued on October 22, 2008, establishing 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 30% of the state’s electricity needs with renewable energy by 2020;

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·   examine smart grid technology and develop additional cogeneration and other generation resources consistent with the state’s greenhouse gas targets; and

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

On January 28, 2009, the NJBPU adopted an order establishing the general process and contents of specific EMP plans that must be filed by December 31, 2009 by New Jersey electric and gas utilities in order to achieve the goals of the EMP. At this time, FirstEnergy cannot determine the impact, if any, the EMP may have on its operations or those of JCP&L.

In support of the New Jersey Governor's Economic Assistance and Recovery Plan, JCP&L announced a proposal to spend approximately $98 million on infrastructure and energy efficiency projects in 2009.  Under the proposal, an estimated $40 million would be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations.  Approximately $34 million would be spent implementing new demand response programs as well as expanding on existing programs.  Another $11 million would be spent on energy efficiency, specifically replacing transformers and capacitor control systems and installing new LED street lights. The remaining $13 million would be spent on energy efficiency programs that would complement those currently being offered. Implementation of the projects is dependent upon resolution of regulatory issues including recovery of the costs associated with the proposal.

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 is pending before the FERC, and 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. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements.

PJM Transmission Rate

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. AEP's 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. 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. Oral arguments were held on April 13, 2009. A decision is expected this summer.

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The FERC’s orders on PJM rate design would 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 would 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 to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement subject to the submission of a compliance filing. The compliance filing was submitted on August 29, 2008, and the FERC issued an order accepting the compliance filing on October 15, 2008. On November 14, 2008, PJM submitted revisions to its tariff to incorporate cost responsibility assignments for below 500 kV upgrades included in PJM’s Regional Transmission Expansion Planning process in accordance with the settlement. The FERC conditionally accepted the compliance filing on January 28, 2009. PJM submitted a further compliance filing on March 2, 2009, which was accepted by the FERC on April 10, 2009. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. An initial decision was issued by the Presiding Judge on September 18, 2008. PJM and FERC trial staff each filed a Brief on Exceptions to the initial decision on October 20, 2008. Briefs Opposing Exceptions were filed on November 10, 2008.

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 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. The effect of this order is to prevent the shift of significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP was denied by the FERC on December 19, 2008. On February 17, 2009, AEP appealed the FERC’s January 31, 2008, and December 19, 2008, orders to the U.S. Court of Appeals for the Seventh Circuit. FESC, on behalf of its affiliated operating utility companies, filed a motion to intervene on March 10, 2009.

Changes ordered for PJM Reliability Pricing Model (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. On September 19, 2008, the FERC denied the RPM Buyers’ complaint. The FERC also ordered PJM to file on or before December 15, 2008, a report on potential adjustments to the RPM program as suggested in a Brattle Group report. On December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the RPM program. PJM also requested that the FERC conduct a settlement hearing to address changes to the RPM and suggested that the FERC should rule on the tariff amendments only if settlement could not be reached in January, 2009. The request for settlement hearings was granted. Settlement had not been reached by January 9, 2009 and, accordingly, FirstEnergy and other parties submitted comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief Judge issued an order terminating settlement discussions. On February 9, 2009, PJM and a group of stakeholders submitted an offer of settlement, which used the PJM December 12, 2008 filing as its starting point, and stated that unless otherwise specified, provisions filed by PJM on December 12, 2008, apply.

On March 26, 2009, the FERC accepted in part, and rejected in part, tariff provisions submitted by PJM, revising certain parts of its RPM. Ordered changes included making incremental improvements to RPM; however, the basic construct of RPM remains intact. On April 3, 2009, PJM filed with the FERC requesting clarification on certain aspects of the March 26, 2009 Order. On April 27, 2009, PJM submitted a compliance filing addressing the changes the FERC ordered in the March 26, 2009 Order; and subsequently, numerous parties filed requests for rehearing of the March 26, 2009 Order. On June 18, 2009, the FERC denied rehearing and request for oral argument of the March 26 Order.

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PJM has reconvened the Capacity Market Evolution Committee to address issues not addressed in the February 2009 settlement in preparation for September 1, 2009 and December 1, 2009 compliance filings that will recommend more incremental improvements to its RPM.

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 and FES. This requirement was 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 submitted 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.

On October 20, 2008, the FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a compliance filing modifying the cost of new entry penalty. Second, the FERC conditionally accepted MISO's compliance filing on the qualifications for purchased power agreements to be capacity resources, load forecasting, loss of load expectation, and planning reserve zones. Additional compliance filings were directed on accreditation of load modifying resources and price responsive demand. Finally, the FERC largely denied rehearing of its March 26 order with the exception of issues related to behind the meter resources and certain ministerial matters. On November 19, 2008, MISO made various compliance filings pursuant to these orders. Issuance of orders on rehearing and two of the compliance filings occurred on February 19, 2009. No material changes were made to MISO’s Resource Adequacy program. On April 16, 2009, the FERC issued an additional order on rehearing and compliance, approving MISO’s proposed financial settlement provision for Resource Adequacy. The MISO Resource Adequacy process was implemented as planned on June 1, 2009, the beginning of the MISO planning year. On June 17, 2009, MISO submitted a compliance filing in response to the FERC’s April 16, 2009 order directing it to address, among others, various market monitoring and mitigation issues. On July 8, 2009, various parties submitted comments on and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific aspects of the MISO’s and Independent Market Monitor’s proposals for market monitoring and mitigation and other issues that it believes the FERC should address and clarify.

FES Sales to Affiliates

FES supplied all of the power requirements for the Ohio Companies pursuant to a Power Supply Agreement that ended on December 31, 2008. On January 2, 2009, FES signed an agreement to provide 75% of the Ohio Companies’ power requirements for the period January 5, 2009 through March 31, 2009. Subsequently, FES signed an agreement to provide 100% of the Ohio Companies’ power requirements for the period April 1, 2009 through May 31, 2009. On March 4, 2009, the PUCO issued an order approving these two affiliate sales agreements. FERC authorization for these affiliate sales was by means of a December 23, 2008 waiver of restrictions on affiliate sales without prior approval of the FERC.

On May 13-14, 2009, the Ohio Companies held an auction to secure generation supply for their PLR obligation. The results of the auction were accepted by the PUCO on May 14, 2009. Twelve bidders qualified to participate in the auction with nine successful bidders each securing a portion of the Ohio Companies' total supply needs. FES was the successful bidder for 51 tranches, and subsequently purchased 11 additional tranches from other bidders. The auction resulted in an overall weighted average wholesale price of 6.15 cents per KWH for generation and transmission. The new prices for PLR service went into effect with usage beginning June 1, 2009, and continuing through May 31, 2011.

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On October 31, 2008, FES executed a Third Restated Partial Requirements Agreement with Met-Ed, Penelec, and Waverly effective November 1, 2008. The Third Restated Partial Requirements Agreement limits the amount of capacity and energy required to be supplied by FES in 2009 and 2010 to approximately two-thirds of those affiliates’ power supply requirements. Met-Ed, Penelec, and Waverly have committed resources in place for the balance of their expected power supply during 2009 and 2010. Under the Third Restated Partial Requirements Agreement, Met-Ed, Penelec, and Waverly are responsible for obtaining additional power supply requirements created by the default or failure of supply of their committed resources. Prices for the power provided by FES were not changed in the Third Restated Partial Requirements Agreement.

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 $808 million for the period 2009-2013.

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 $37,500 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, the generation of more electricity at lower-emitting plants, and/or using emission allowances. 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.

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 and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s 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 was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices or repowering and provides for stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree, including repowering Burger Units 4 and 5 for biomass fuel consumption, are currently estimated to be $706 million for 2009-2012 (with $414 million expected to be spent in 2009).

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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. In July 2008, three additional complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania 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. On October 14, 2008, the Court granted FGCO’s motion to consolidate discovery for all four complaints pending against the Bruce Mansfield Plant. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints. The Pennsylvania Department of Health, under a Cooperative Agreement with the Agency for Toxic Substances and Disease Registry, completed a Health Consultation regarding the Mansfield Plant and issued a report dated March 31, 2009 which concluded there is insufficient sampling data to determine if any public health threat exists for area residents due to emissions from the Mansfield Plant. The report recommended additional air monitoring and sample analysis in the vicinity of the Mansfield Plant which the Pennsylvania Department of Environmental Protection is currently conducting.

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.  On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. Specifically, Connecticut and New Jersey allege that "modifications" at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed.  On December 5, 2008, New Jersey filed an amended complaint, adding claims with respect to alleged modifications that occurred after GPU’s sale of the plant. Met-Ed filed a Motion to Dismiss the claims in New Jersey’s Amended Complaint and Connecticut’s Complaint on February 19, 2009. On January 14, 2009, the EPA issued a NOV to Reliant alleging new source review violations at the Portland Generation Station based on “modifications” dating back to 1986. Met-Ed is unable to predict the outcome of this matter. The EPA’s January 14, 2009, NOV also alleged new source review violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of Keystone Station and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter. On June 1, 2009, the Court held oral argument on Met-Ed’s motion to dismiss the complaint.

On June 11, 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. 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. Mission Energy is seeking indemnification from Penelec, 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. The scope of Penelec’s indemnity obligation to and from Mission Energy 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 Administrative Consent Order modifying that request and setting forth a schedule for FGCO’s response. On October 27, 2008, FGCO received a second request from the EPA for information pursuant to Section 114(a) of the CAA for additional operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants. FGCO intends to fully comply with the EPA’s information requests, but, at this time, is unable to predict the outcome of this matter.

On August 18, 2008, FirstEnergy received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding its formerly-owned Avon Lake and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. FirstEnergy intends to fully comply with the EPA’s information request, 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 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 requires 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 2.5 million tons annually and NOX emissions to 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.” On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. On December 23, 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s July 11, 2008 opinion. On July 10, 2009, the United States Court of Appeals for the District of Columbia ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOX SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the "8-hour" ozone NAAQS. FGCO's future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA 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. On October 17, 2008, the EPA (and an industry group) petitioned the United States Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the EPA moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the EPA’s petition and denied the industry group’s petition. The EPA is developing 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 any future regulations 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. On January 30, 2009, the Commonwealth Court of Pennsylvania declared Pennsylvania’s mercury rule “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule. It is anticipated that compliance with these regulations, if the Commonwealth Court’s rulings were reversed on appeal and Pennsylvania’s mercury rule was 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.

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, by 2012, the amount of man-made GHG, including CO2, emitted by developed countries. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. 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. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity used in the United States comes from renewable sources by 2012, increasing to 25% by 2025, and implementing an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050.

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 House of Representatives passed one such bill, the American Clean Energy and Security Act of 2009, on June 26, 2009. 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.

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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 April 17, 2009, the EPA released a “Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s proposed finding concludes that the atmospheric concentrations of several key greenhouse gases threaten the health and welfare of future generations and that the combined emissions of these gases by motor vehicles contribute to the atmospheric concentrations of these key greenhouse gases and hence to the threat of climate change. Although the EPA’s proposed finding, if finalized, does not establish emission requirements for motor vehicles, such requirements would be expected to occur through further rulemakings. Additionally, while the EPA’s proposed findings do not specifically address stationary sources, including electric generating plants, those findings, if finalized, would be expected to support the establishment of future emission requirements by the EPA for stationary sources.

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 1, 2009, the Supreme Court of the United States reversed one significant aspect of the Second Circuit Court’s opinion and decided that 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 and 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.

The U.S. Attorney's Office in Cleveland, Ohio has advised FGCO that it is considering prosecution under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007. FGCO is unable to predict the outcome of this matter.

Regulation of Waste Disposal

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. In February 2009, the EPA requested comments from the states on options for regulating coal combustion wastes, including regulation as non-hazardous waste or regulation as a hazardous waste. In March and June 2009, the EPA requested information from FGCO’s Bruce Mansfield Plant regarding the management of coal combustion wastes. FGCO's future cost of compliance with any coal combustion waste regulations which may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the states.

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The Utilities have been named as potentially responsible parties 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 potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the consolidated balance sheet as of June 30, 2009, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $104 million have been accrued through June 30, 2009. Included in the total are accrued liabilities of approximately $68 million for environmental remediation of former manufactured gas plants and gas holder facilities 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.  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 due to the outages.

After various motions, rulings and appeals, the Plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability, and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. The class was decertified twice by the trial court, and appealed both times by the Plaintiffs, with the results being that: (1) the Appellate Division limited the class only 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 which resulted in planned and unplanned outages in the area during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. On March 31, 2009, the trial court again granted JCP&L’s motion to decertify the class. On April 20, 2009, the Plaintiffs filed a motion for leave to take an interlocutory appeal to the trial court's decision to decertify the class, which was granted by the Appellate Division on June 15, 2009. According to the scheduling order issued by the Appellate Division, Plaintiffs' opening brief is due on August 25, 2009, JCP&L's opposition brief is due on September 25, 2009, and Plaintiffs' reply is due on October 5, 2009.

Nuclear Plant Matters

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. On June 8, 2009, the NRC issued the final Safety Evaluation Report (SER) supporting the renewed license for Beaver Valley Units 1 and 2. On July 8, 2009, the NRC’s Advisory Committee on Reactor Safeguards (ACRS) held a public meeting to consider the NRC’s final SER. Much of the ACRS’ discussion involved questions raised by a letter from Citizens Power regarding the extent of corrective actions for the 2009 discovery of a penetration in the Beaver Valley Unit 1 containment liner. On July 28, 2009, FENOC submitted to the NRC further clarifications on the supplemental volumetric examinations of Beaver Valley’s containment liners. FENOC anticipates another meeting with the ACRS regarding the container liner during September 2009. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and is scheduled 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.

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of June 30, 2009, FirstEnergy had approximately $1.7 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 provided an additional $80 million parental guarantee associated with the funding of decommissioning costs for these units and indicated that it planned to contribute an additional $80 million to these trusts by 2010.  As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s obligations to fund the trusts may increase. The recent disruption in the capital markets and its effects on particular businesses and the economy in general also affects the values of the nuclear decommission trusts. On June 18, 2009, the NRC informed FENOC that its review tentatively concluded that a shortfall ($147.5 million net present value) existed in the value of the decommissioning trust fund for Beaver Valley Unit 1. On July 28, 2009, FENOC submitted a letter to the NRC that stated reasonable assurance of decommissioning funding is provided for Beaver Valley Unit 1 through a combination of the existing trust fund balances, the existing $80 million parental guarantee from FirstEnergy and maintaining the plant in a safe-store configuration, or extended safe shutdown condition, after plant shutdown. Renewal of the operating license for Beaver Valley Unit 1, as described above, would mitigate the estimated shortfall in the unit’s nuclear decommissioning funding status. FENOC continues to communicate with the NRC regarding future actions to provide reasonable assurance for decommissioning funding. Such actions may include additional parental guarantees or contributions to those funds.

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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.

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. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. A final order identifying the individual damage amounts was issued on October 31, 2007 and 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 and oral arguments were held in the fall. On February 25, 2009, the federal district court denied JCP&L’s motion to vacate the arbitration decision and granted the union’s motion to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009. The appeal process could take as long as 24 months. JCP&L recognized a liability for the potential $16 million award in 2005. Post-judgment interest began to accrue as of February 25, 2009, and the liability will be adjusted accordingly.

The bargaining unit employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. On July 24, 2009, FirstEnergy declared that bargaining was at an impasse and portions of its last contract offer were implemented August 1, 2009.  A federal mediator is continuing to assist the parties in reaching a negotiated contract settlement. FirstEnergy has a strike mitigation plan ready in the event of a strike.

On May 21, 2009, 517 Penelec employees, represented by the International Brotherhood of Electrical Workers (IBEW) Local 459, elected to strike. In response, on May 22, 2009, Penelec implemented its work-continuation plan to use nearly 400 non-represented employees with previous line experience and training drawn from Penelec and other FirstEnergy operations to perform service reliability and priority maintenance work in Penelec’s service territory. Penelec's IBEW Local 459 employees ratified a three-year contract agreement on July 19, 2009, and returned to work on July 20, 2009.

On June 26, 2009, FirstEnergy announced that seven of its union locals, representing about 2,600 employees, have ratified contract extensions. These unions include employees from Penelec, Penn, CEI, OE and TE, along with certain power plant employees.

On July 8, 2009, FirstEnergy announced that employees of Met-Ed represented by IBEW Local 777 ratified a two-year contract. Union members had been working without a contract since the previous agreement expired on April 30, 2009.

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

FSP FAS 132 (R)-1 – “Employers’ Disclosures about Postretirement Benefit Plan Assets”

In December 2008, the FASB issued Staff Position FAS 132(R)-1, which provides guidance on an employer’s disclosures about assets of a defined benefit pension or other postretirement plan. Requirements of this FSP include disclosures about investment policies and strategies, categories of plan assets, fair value measurements of plan assets, and significant categories of risk. This FSP is effective for fiscal years ending after December 15, 2009. FirstEnergy will expand its disclosures related to postretirement benefit plan assets as a result of this FSP.

SFAS 166 – “Accounting for Transfers of Financial Assets – an amendment of FASB Statement No. 140”

In June 2009, the FASB issued SFAS 166, which amends the derecognition guidance in SFAS 140 and eliminates the concept of a qualifying special-purpose entity (QSPE). It removes the exception from applying FIN 46R to QSPEs and requires an evaluation of all existing QSPEs to determine whether they must be consolidated in accordance with SFAS 167. This Statement is effective for financial asset transfers that occur in fiscal years beginning after November 15, 2009. FirstEnergy does not expect this Standard to have a material effect upon its financial statements.

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SFAS 167 – “Amendments to FASB Interpretation No. 46(R)”

In June 2009, the FASB issued SFAS 167, which amends the consolidation guidance applied to VIEs. This Statement replaces the quantitative approach previously required to determine which entity has a controlling financial interest in a VIE with a qualitative approach. Under the new approach, the primary beneficiary of a VIE is the entity that has both (a) the power to direct the activities of the VIE that most significantly impact the entity’s economic performance, and (b) the obligation to absorb losses of the entity, or the right to receive benefits from the entity, that could be significant to the VIE. SFAS 167 also requires ongoing reassessments of whether an entity is the primary beneficiary of a VIE and enhanced disclosures about an entity’s involvement in VIEs. This Statement is effective for fiscal years beginning after November 15, 2009. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial statements.

SFAS 168 – “The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162”

In June 2009, the FASB issued SFAS 168, which recognizes the FASB Accounting Standards CodificationTM (Codification) as the source of authoritative GAAP. It also recognizes that rules and interpretative releases of the SEC under federal securities laws are sources of authoritative GAAP for SEC registrants. The Codification supersedes all non-SEC accounting and reporting standards. This Statement is effective for financial statements issued for interim and annual periods ending after September 15, 2009. This Statement will change how FirstEnergy references GAAP in its financial statement disclosures.

44

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, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2009 and 2008 and the consolidated statement of cash flows for the six-month periods ended June 30, 2009 and 2008. 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, 2008, and the related consolidated statements of income, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements.  As discussed in Note 6 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest.  The accompanying December 31, 2008 consolidated balance sheet reflects this change.

PricewaterhouseCoopers LLP

Cleveland, Ohio

August 3, 2009

45

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months						Six Months
	Ended June 30						Ended June 30
	2009			2008			2009			2008
	(In millions, except per share amounts)
REVENUES:
Electric utilities	$	2,791		$	2,865		$	5,811		$	5,778
Unregulated businesses		480			380			794			744
Total revenues *		3,271			3,245			6,605			6,522
EXPENSES:
Fuel		276			316			588			644
Purchased power		1,024			1,070			2,167			2,070
Other operating expenses		612			781			1,439			1,580
Provision for depreciation		185			168			362			332
Amortization of regulatory assets		233			246			642			504
Deferral of regulatory assets		(45	)		(98	)		(136	)		(203	)
General taxes		184			180			395			395
Total expenses		2,469			2,663			5,457			5,322
OPERATING INCOME		802			582			1,148			1,200
OTHER INCOME (EXPENSE):
Investment income		27			16			16			33
Interest expense		(206	)		(188	)		(400	)		(367	)
Capitalized interest		33			13			61			21
Total other expense		(146	)		(159	)		(323	)		(313	)
INCOME BEFORE INCOME TAXES		656			423			825			887
INCOME TAXES		248			160			302			347
NET INCOME		408			263			523			540
Less:  Noncontrolling interest income (loss)		(6	)		-			(10	)		1
EARNINGS AVAILABLE TO FIRSTENERGY CORP.	$	414		$	263		$	533		$	539
BASIC EARNINGS PER SHARE OF COMMON STOCK	$	1.36		$	0.86		$	1.75		$	1.77
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING		304			304			304			304
DILUTED EARNINGS PER SHARE OF COMMON STOCK	$	1.36		$	0.85		$	1.75		$	1.75
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING		305			307			306			307
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	-		$	-		$	0.55		$	0.55
* Includes excise tax collections of $95 million and $100 million in the three months ended June 30, 2009 and 2008, respectively, and
$204 million and $214 million in the six months ended June 2009 and 2008, respectively.
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.

46

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
	Three Months						Six Months
	Ended June 30						Ended June 30
	2009			2008			2009			2008
	(In millions)
NET INCOME	$	408		$	263		$	523		$	540
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		469			(20	)		504			(40	)
Unrealized gain (loss) on derivative hedges		23			8			38			(5	)
Change in unrealized gain on available-for-sale securities		37			(23	)		32			(81	)
Other comprehensive income (loss)		529			(35	)		574			(126	)
Income tax expense (benefit) related to other comprehensive income		227			(14	)		242			(47	)
Other comprehensive income (loss), net of tax		302			(21	)		332			(79	)
COMPREHENSIVE INCOME		710			242			855			461
LESS: COMPREHENSIVE INCOME ATTRIBUTABLE
TO NONCONTROLLING INTEREST		(6	)		-			(10	)		1
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP.	$	716		$	242		$	865		$	460
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
these statements.

47

FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,			December 31,
	2009			2008
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	900		$	545
Receivables-
Customers (less accumulated provisions of $26 million and $28 million,
respectively, for uncollectible accounts)		1,313			1,304
Other (less accumulated provisions of $9 million for uncollectible accounts)		127			167
Materials and supplies, at average cost		644			605
Prepaid taxes		457			283
Other		209			149
		3,650			3,053
PROPERTY, PLANT AND EQUIPMENT:
In service		27,315			26,482
Less - Accumulated provision for depreciation		11,113			10,821
		16,202			15,661
Construction work in progress		2,307			2,062
		18,509			17,723
INVESTMENTS:
Nuclear plant decommissioning trusts		1,733			1,708
Investments in lease obligation bonds		553			598
Other		696			711
		2,982			3,017
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		5,575			5,575
Regulatory assets		2,819			3,140
Power purchase contract asset		214			434
Other		557			579
		9,165			9,728
	$	34,306		$	33,521
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,984		$	2,476
Short-term borrowings		2,397			2,397
Accounts payable		806			794
Accrued taxes		259			333
Other		782			1,098
		6,228			7,098
CAPITALIZATION:
Common stockholders’ equity-
Common stock, $0.10 par value, authorized 375,000,000 shares-		31			31
304,835,407 shares outstanding
Other paid-in capital		5,465			5,473
Accumulated other comprehensive loss		(1,048	)		(1,380	)
Retained earnings		4,525			4,159
Total common stockholders' equity		8,973			8,283
Noncontrolling interest		28			32
Total equity		9,001			8,315
Long-term debt and other long-term obligations		10,399			9,100
		19,400			17,415
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		2,447			2,163
Asset retirement obligations		1,379			1,335
Deferred gain on sale and leaseback transaction		1,010			1,027
Power purchase contract liability		750			766
Retirement benefits		1,473			1,884
Lease market valuation liability		285			308
Other		1,334			1,525
		8,678			9,008
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 8)
	$	34,306		$	33,521
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.

48

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30
	2009			2008
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	523		$	540
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		362			332
Amortization of regulatory assets		642			504
Deferral of regulatory assets		(136	)		(203	)
Nuclear fuel and lease amortization		52			51
Deferred purchased power and other costs		(135	)		(95	)
Deferred income taxes and investment tax credits, net		69			129
Investment impairment		39			38
Deferred rents and lease market valuation liability		(59	)		(101	)
Accrued compensation and retirement benefits		(93	)		(140	)
Stock-based compensation		(2	)		(72	)
Gain on asset sales		(12	)		(41	)
Electric service prepayment programs		(10	)		(39	)
Cash collateral, net		48			67
Decrease (increase) in operating assets-
Receivables		32			(136	)
Materials and supplies		6			(31	)
Prepaid taxes		(204	)		(393	)
Increase (decrease) in operating liabilities-
Accounts payable		(11	)		152
Accrued taxes		(101	)		(190	)
Other		92			(53	)
Net cash provided from operating activities		1,102			319
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		1,679			549
Short-term borrowings, net		-			1,705
Redemptions and Repayments-
Long-term debt		(881	)		(719	)
Net controlled disbursement activity		(15	)		8
Common stock dividend payments		(335	)		(335	)
Other		(22	)		19
Net cash provided from financing activities		426			1,227
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(1,143	)		(1,617	)
Proceeds from asset sales		19			56
Sales of investment securities held in trusts		1,001			726
Purchases of investment securities held in trusts		(1,041	)		(775	)
Cash investments		40			65
Other		(49	)		(60	)
Net cash used for investing activities		(1,173	)		(1,605	)
Net change in cash and cash equivalents		355			(59	)
Cash and cash equivalents at beginning of period		545			129
Cash and cash equivalents at end of period	$	900		$	70
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral
part of these statements.

49

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 and maintains 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 have been primarily derived 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 included a full-requirements PSA with OE, CEI and TE to supply each of their default service obligations through December 31, 2008, at prices that considered their respective PUCO-authorized billing rates. See Regulatory Matters – Ohio below for a discussion of Ohio power supply procurement issues for 2009 and beyond. FES continues to have 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 2009. This sales agreement is renewed annually unless cancelled by either party with at least a sixty-day written notice prior to the end of the calendar year. FES also supplied, through May 31, 2009, a portion of Penn's default service requirements at market-based rates as a result of Penn's 2008 competitive solicitations. FES' revenues also include competitive retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania, New Jersey, Maryland, Michigan and Illinois. These sales may provide a greater portion of revenues in future years depending upon FES' participation in its Ohio and Pennsylvania utility affiliates' power procurement arrangements.

The demand for electricity produced and sold by FES, along with the value of that electricity, is materially impacted by conditions in competitive power markets, global economic activity, economic activity in the Midwest and Mid-Atlantic regions, and weather conditions in FirstEnergy’s service territories. The current recessionary economic conditions, particularly in the automotive and steel industries, compounded by unusually mild regional summertime temperatures, have directly impacted FES’ operations and revenues.

The level of demand for electricity directly impacts FES’ generation revenues, the quantity of electricity produced, purchased power expense and fuel expense. FirstEnergy and FES have taken various actions and instituted a number of changes in operating practices to mitigate these external influences. These actions include employee severances, wage reductions, employee and retiree benefit changes, reduced levels of overtime and the use of fewer contractors. However, the continuation of recessionary economic conditions, coupled with unusually mild weather patterns and the resulting impact on electricity prices and demand could impact FES’ future operating performance and financial condition and may require further changes in FES’ operations.

Results of Operations

In the first six months of 2009, net income increased to $468million from $158million in the same period in 2008. The increase in net income includes FGCO’s $252 million pre-tax gain from the sale of 9% of its participation in OVEC ($158 million after-tax) and an increase in gross sales margins.

Revenues

Revenues increased by $397million in the first six months of 2009 compared to the same period in 2008 due to the OVEC sale and increases in revenues from non-affiliated and affiliated wholesale sales, partially offset by lower retail generation sales. The increase in revenues resulted from the following sources:

	Six  Months Ended
	June 30				Increase
Revenues by Type of Service	2009		2008		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	174	$	315	$	(141	)
Wholesale		311		298		13
Total Non-Affiliated Generation Sales		485		613		(128	)
Affiliated Generation Sales		1,732		1,480		252
Transmission		41		66		(25	)
Sale of OVEC participation interest		252		-		252
Other		57		11		46
Total Revenues	$	2,567	$	2,170	$	397

50

The lower retail generation revenues resulted from the expiration of certain government aggregation programs in the MISO market at the end of 2008 that were supplied by FES, partially offset by increased retail revenues in both the PJM and MISO markets. The increase in non-aggregation retail revenues in MISO was primarily the result of the acquisition of new customers and higher unit prices. The increase in PJM retail sales resulted from higher unit prices. Higher non-affiliated wholesale revenues resulted from increased sales volumes and prices in MISO partially offset by decreased sales volumes and prices in PJM.

The increase in affiliated company wholesale revenues was due to higher unit prices to the Ohio Companies and increased sales volumes to Met-Ed and Penelec, partially offset by lower sales volumes to the Ohio Companies. The higher unit prices reflected the results of the Ohio Companies’ power procurement processes in the first half of 2009 (see Regulatory Matters – Ohio). In the first quarter of 2009, FES supplied approximately 75% of the Ohio Companies’ power requirements as one of four winning bidders in the Ohio Companies' RFP process. In the second quarter of 2009, FES supplied 100% of the power for the Ohio Companies’ PLR service in April and May 2009, and approximately 56% of the Ohio Companies' supply needs in June 2009. Subsequent to the Ohio Companies’ CBP, FES purchased additional tranches from other winning bidders and effective August 1, 2009, FES will supply 62% of the Ohio Companies’ PLR generation requirements.

Increased sales volumes to the Pennsylvania Companies reflect higher sales to Met-Ed and Penelec, following the expiration of a third-party supply contract for the utilities at the end of 2008, partially offset by lower sales to Penn due to decreased default service requirements in the first six months of 2009 compared to the first six months of 2008. While unit prices for each of the Pennsylvania Companies did not change, the mix of sales among the companies caused the overall composite price to decline.

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 2009 compared to the same period last year:

	Increase
Source of Change in Non-Affiliated Generation Revenues	(Decrease)
	(In millions)
Retail:
Effect of 57.8% decrease in sales volumes	$	(182	)
Change in prices		41
		(141	)
Wholesale:
Effect of 4.1% decrease in sales volumes		(12	)
Change in prices		25
		13
Net Decrease in Non-Affiliated Generation Revenues	$	(128	)

	Increase
Source of Change in Affiliated Generation Revenues	(Decrease)
	(In millions)
Ohio Companies:
Effect of 19.2% decrease in sales volumes	$	(218	)
Change in prices		449
		231
Pennsylvania Companies:
Effect of 10.6% increase in sales volumes		37
Change in prices		(16	)
		21
Net Increase in Affiliated Generation Revenues	$	252

Transmission revenue decreased $25 million primarily due to reduced retail loads in MISO. Other revenue increased by $46 million principally from rental income associated with NGC's acquisition of additional equity interests in Perry and Beaver Valley Unit 2.

Expenses

Total expenses decreased by $58 million in the first six months of 2009 compared with the same period of 2008. The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first six months of 2009 from the same period last year:

51

Source of Change in Fuel and Purchased Power	Increase  (Decrease)
	(In millions)
Fossil Fuel:
Change due to increased unit costs	$	65
Change due to volume consumed		(118	)
		(53	)
Nuclear Fuel:
Change due to increased unit costs		5
Change due to volume consumed		(7	)
		(2	)
Non-affiliated Purchased Power:
Change due to increased unit costs		22
Change due to volume purchased		(103	)
		(81	)
Affiliated Purchased Power:
Change due to increased unit costs		51
Change due to volume purchased		3
		54
Net Decrease in Fuel and Purchased Power Costs	$	(82	)

Fossil fuel costs decreased $53 million in the first six months of 2009 as a result of decreased coal consumption, reflecting lower generation. Higher unit prices, which are expected to continue during the remainder of 2009, were due to increased fuel costs associated with purchases of eastern coal. Nuclear fuel costs were relatively unchanged in the first six months of 2009 from last year.

Purchased power costs from non-affiliates decreased primarily as a result of reduced volume requirements, partially offset by higher capacity costs. Purchases from affiliated companies increased as a result of higher unit costs on purchases from the OE’s and TE’s leasehold interests in Beaver Valley Unit 2 and Perry.

Other operating expenses increased by $1million in the first six months of 2009 from the same period of 2008. Higher expenses in the 2009 period for organizational restructuring costs ($4 million), increased nuclear operating costs for an additional refueling outage ($9 million) and higher transmission expenses due to increased charges in the PJM market ($24 million) were offset by lower fossil operating costs ($32 million) and lease expenses ($5 million). Decreased fossil operating costs were primarily due to reduced maintenance activities and more labor dedicated to capital projects compared to the 2008 period. Lower lease expenses were principally due to the transfer of CEI’s and TE’s leasehold improvements for the Mansfield Plant to FGCO during the first quarter of 2008.

Depreciation expense increased by $21 million in the first six months of 2009 primarily due to NGC’s increased ownership interest in Beaver Valley Unit 2 and Perry.

Other Expense

Other expense decreased by $11million in the first six months of 2009 from the same period of 2008 primarily due to a $12 million decrease in interest expense to affiliates due to lower rates on loans from the unregulated money pool and a $7 million increase in capitalized interest. Partially offsetting the lower interest expense was an $8 million increase in impairments (net of realized investment income) on the nuclear decommissioning trust investments during the 2009 period.

The decrease in FES’ effective income tax rate for the first six months of 2009 is primarily due to the phase out of the Ohio income-based franchise tax at the end of 2008 and an increase in the manufacturing deduction in the 2009 period.

Working Capital

As of June 30, 2009, FES’ net deficit in working capital (current assets less current liabilities) was principally due to short-term borrowings and the classification of certain variable interest rate PCRBs as currently payable long-term debt. As of June 30, 2009, FES had access to $1.3 billion of short-term financing under revolving credit facilities. FES also has the ability to borrow from FirstEnergy under the unregulated money pool to meet its short-term working capital requirements.

52

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.

53

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, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2009 and 2008 and the consolidated statement of cash flows for the six-month periods ended June 30, 2009 and 2008. 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, 2008, 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 24, 2009, 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, 2008, 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 3, 2009

54

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30						June 30
	2009			2008			2009			2008
	(In thousands)
REVENUES:
Electric sales to affiliates	$	839,751		$	704,283		$	1,732,441		$	1,480,590
Electric sales to non-affiliates		205,379			324,276			485,125			612,617
Other		296,022			42,719			349,692			77,187
Total revenues		1,341,152			1,071,278			2,567,258			2,170,394
EXPENSES:
Fuel		270,309			310,550			576,467			632,239
Purchased power from non-affiliates		185,613			220,339			345,955			427,063
Purchased power from affiliates		51,249			34,528			114,456			60,013
Other operating expenses		278,264			287,738			585,620			584,284
Provision for depreciation		65,548			56,160			126,921			105,902
General taxes		21,285			19,795			44,661			42,992
Total expenses		872,268			929,110			1,794,080			1,852,493
OPERATING INCOME		468,884			142,168			773,178			317,901
OTHER INCOME (EXPENSE):
Miscellaneous income (expense)		13,265			(2,074	)		(13,098	)		(4,978	)
Interest expense to affiliates		(3,315	)		(10,728	)		(6,294	)		(17,938	)
Interest expense - other		(26,271	)		(24,505	)		(48,798	)		(49,040	)
Capitalized interest		14,028			10,541			24,106			17,204
Total other expense		(2,293	)		(26,766	)		(44,084	)		(54,752	)
INCOME BEFORE INCOME TAXES		466,591			115,402			729,094			263,149
INCOME TAXES		169,189			47,308			261,011			105,071
NET INCOME		297,402			68,094			468,083			158,078
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		72,121			(1,821	)		74,689			(3,641	)
Unrealized gain (loss) on derivative hedges		15,041			(17,920	)		26,057			(12,202	)
Change in unrealized gain on available-for-sale securities		39,504			(17,709	)		38,027			(69,561	)
Other comprehensive income (loss)		126,666			(37,450	)		138,773			(85,404	)
Income tax expense (benefit) related to other
comprehensive income		50,625			(13,313	)		55,334			(30,716	)
Other comprehensive income (loss), net of tax		76,041			(24,137	)		83,439			(54,688	)
TOTAL COMPREHENSIVE INCOME	$	373,443		$	43,957		$	551,522		$	103,390
The accompanying Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are an integral part of
these balance sheets.

55

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,			December 31,
	2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	120,034		$	39
Receivables-
Customers (less accumulated provisions of $3,904,000 and $5,899,000,
respectively, for uncollectible accounts)		75,753			86,123
Associated companies		215,362			378,100
Other (less accumulated provisions of $6,702,000 and $6,815,000
respectively, for uncollectible accounts)		19,309			24,626
Notes receivable from associated companies		370,345			129,175
Materials and supplies, at average cost		550,212			521,761
Prepayments and other		98,381			112,535
		1,449,396			1,252,359
PROPERTY, PLANT AND EQUIPMENT:
In service		10,226,785			9,871,904
Less - Accumulated provision for depreciation		4,400,182			4,254,721
		5,826,603			5,617,183
Construction work in progress		2,019,748			1,747,435
		7,846,351			7,364,618
INVESTMENTS:
Nuclear plant decommissioning trusts		1,040,410			1,033,717
Long-term notes receivable from associated companies		-			62,900
Other		29,212			61,591
		1,069,622			1,158,208
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits		151,457			267,762
Lease assignment receivable from associated companies		71,356			71,356
Goodwill		24,248			24,248
Property taxes		50,104			50,104
Unamortized sale and leaseback costs		74,281			69,932
Other		62,305			96,434
		433,751			579,836
	$	10,799,120		$	10,355,021
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,632,264		$	2,024,898
Short-term borrowings-
Associated companies		309,832			264,823
Other		1,100,000			1,000,000
Accounts payable-
Associated companies		367,395			472,338
Other		168,485			154,593
Accrued taxes		68,759			79,766
Other		180,990			248,439
		3,827,725			4,244,857
CAPITALIZATION:
Common stockholder's equity -
Common stock, without par value, authorized 750 shares,
7 shares outstanding		1,463,074			1,464,229
Accumulated other comprehensive loss		(8,432	)		(91,871	)
Retained earnings		2,040,148			1,572,065
Total common stockholder's equity		3,494,790			2,944,423
Long-term debt and other long-term obligations		965,677			571,448
		4,460,467			3,515,871
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		1,009,727			1,026,584
Accumulated deferred investment tax credits		60,562			62,728
Asset retirement obligations		891,505			863,085
Retirement benefits		131,882			194,177
Property taxes		50,104			50,104
Lease market valuation liability		284,952			307,705
Other		82,196			89,910
		2,510,928			2,594,293
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	10,799,120		$	10,355,021
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an integral part
of these balance sheets.

56

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30
	2009			2008
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	468,083		$	158,078
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		126,921			105,902
Nuclear fuel and lease amortization		53,265			51,207
Deferred rents and lease market valuation liability		(55,493	)		(52,537	)
Deferred income taxes and investment tax credits, net		63,309			51,961
Investment impairment		36,154			33,533
Accrued compensation and retirement benefits		(10,594	)		(8,399	)
Commodity derivative transactions, net		17,688			3,705
Gain on asset sales		(9,635	)		(8,836	)
Cash collateral, net		40,471			(5,355	)
Decrease (increase) in operating assets:
Receivables		179,373			(86,773	)
Materials and supplies		16,609			(27,867	)
Prepayments and other current assets		7,555			(14,512	)
Increase (decrease) in operating liabilities:
Accounts payable		(102,907	)		(37,794	)
Accrued taxes		(14,333	)		(98,948	)
Accrued interest		1,871			(1,603	)
Other		(6,121	)		(16,743	)
Net cash provided from operating activities		812,216			45,019
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		681,675			455,735
Short-term borrowings, net		145,009			1,652,643
Redemptions and Repayments-
Long-term debt		(622,853	)		(458,377	)
Common stock dividend payments		-			(10,000	)
Net cash provided from financing activities		203,831			1,640,001
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(634,967	)		(1,152,502	)
Proceeds from asset sales		15,771			10,875
Sales of investment securities held in trusts		537,078			384,692
Purchases of investment securities held in trusts		(550,730	)		(404,502	)
Loans to associated companies, net		(241,170	)		(461,496	)
Other		(22,034	)		(62,087	)
Net cash used for investing activities		(896,052	)		(1,685,020	)
Net change in cash and cash equivalents		119,995			-
Cash and cash equivalents at beginning of period		39			2
Cash and cash equivalents at end of period	$	120,034		$	2
The accompanying Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are an
integral part of these balance sheets.

57

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 franchise customers electing to retain OE and Penn as their power supplier. Until December 31, 2008, OE purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that reflected the rates approved by the PUCO. See Regulatory Matters – Ohio below for a discussion of Ohio power supply procurement issues for 2009 and beyond.

Results of Operations

In the first six months of 2009, net income decreased to $45 million from $93 million in the same period of 2008. The decrease primarily resulted from the completion of the recovery of transition costs at the end of 2008 and accrued obligations principally associated with the implementation of the ESP in 2009.

Revenues

Revenues increased by $159 million, or 12.6%, in the first six months of 2009 compared with the same period in 2008, primarily due to increases in retail generation revenues ($213 million) and wholesale revenues ($59 million), partially offset by decreases in distribution throughput revenues ($109 million).

Retail generation revenues increased primarily due to higher average prices across all customer classes and increased KWH sales to residential and commercial customers, reflecting a decrease in customer shopping for those sectors as most of OE’s franchise customers returned to PLR service in December 2008. Reduced industrial KWH sales reflected weakened economic conditions in OE’s service territory. Average prices increased primarily due to an increase in OE's fuel cost recovery rider that was effective from January through May 2009. Effective June 1, 2009, the transmission tariff ended and the recovery of transmission costs is included in the generation rate established under OE’s CBP.

Changes in retail generation sales and revenues in the first six months of 2009 from the same period in 2008 are summarized in the following tables:

Retail Generation KWH Sales	Increase (Decrease)
Residential		12.9	%
Commercial		19.1	%
Industrial		(10.8	)%
Net Increase in Generation Sales		6.9	%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	98
Commercial		83
Industrial		32
Increase in Generation Revenues	$	213

Revenues from distribution throughput decreased by $109 million in the first six months of 2009 compared to the same period in 2008 due to lower average unit prices and lower KWH deliveries to all customer classes. Reduced deliveries to commercial and industrial customers reflect the weakened economy. Transition charges that ceased effective January 1, 2009, with the full recovery of related costs, were partially offset by a July 2008 increase to a PUCO-approved transmission rider and a January 2009 distribution rate increase (see Regulatory Matters – Ohio).

58

Changes in distribution KWH deliveries and revenues in the first six months of 2009 from the same period in 2008 are summarized in the following tables.

Distribution KWH Deliveries	Decrease
Residential		(0.9	)%
Commercial		(3.6	)%
Industrial		(25.8	)%
Decrease in Distribution Deliveries		(10.4	)%

Distribution Revenues	Decrease
	(In millions)
Residential	$	(14	)
Commercial		(44	)
Industrial		(51	)
Decrease in Distribution Revenues	$	(109	)

Expenses

Total expenses increased by $223 million in the first six months of 2009 from the same period of 2008. The following table presents changes from the prior year by expense category.

Expenses – Changes	Increase (Decrease)
		(In millions)
Purchased power costs	$	235
Other operating costs		(8	)
Provision for depreciation		1
Amortization of regulatory assets, net		(3	)
General taxes		(2	)
Net Increase in Expenses	$	223

Higher purchased power costs reflect the results of OE’s power procurement process for retail customers in the first six months of 2009 (see Regulatory Matters – Ohio) and higher volumes due to increased retail generation KWH sales. The decrease in other operating costs for the first six months of 2009 was primarily due to lower MISO transmission expenses (included in the cost of power purchased from others beginning June 1, 2009), partially offset by accruals for economic development programs and energy efficiency obligations. Lower amortization of net regulatory assets was primarily due to the conclusion of transition cost recovery in 2008, partially offset by lower MISO transmission cost deferrals and lower RCP distribution deferrals. The decrease in general taxes for the first six months of 2009 was primarily due to lower Ohio KWH taxes.

Other Expenses

Other expenses increased by $11 million in the first six months of 2009 compared to the same period in 2008 primarily due to higher interest expense associated with the issuance of $300 million of FMBs by OE in October 2008.

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 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.

59

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, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2009 and 2008 and the consolidated statement of cash flows for the six-month periods ended June 30, 2009 and 2008. 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, 2008, 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 24, 2009, we expressed an unqualified opinion on those consolidated financial statements.  As discussed in Note 6 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest.  The accompanying December 31, 2008 consolidated balance sheet reflects this change.

PricewaterhouseCoopers LLP

Cleveland, Ohio

August 3, 2009

60

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended							Six Months Ended
	June 30							June 30
	2009			2008				2009			2008
	(In thousands)
STATEMENTS OF INCOME
REVENUES:
Electric sales	$	647,224		$	583,268			$	1,367,235		$	1,205,539
Excise and gross receipts tax collections		24,948			26,287				53,928			56,665
Total revenues		672,172			609,555				1,421,163			1,262,204
EXPENSES:
Purchased power from affiliates		314,870			280,024				647,206			599,735
Purchased power from non-affiliates		98,330			28,025				236,143			48,500
Other operating costs		111,938			137,619				269,768			277,945
Provision for depreciation		21,996			21,414				43,509			42,907
Amortization of regulatory assets, net		22,295			21,955				42,506			45,082
General taxes		43,903			44,389				93,023			94,842
Total expenses		613,332			533,426				1,332,155			1,109,011
OPERATING INCOME		58,840			76,129				89,008			153,193
OTHER INCOME (EXPENSE):
Investment income		10,149			11,488				19,511			26,543
Miscellaneous income (expense)		2,681			(126	)			1,871			(3,778	)
Interest expense		(21,469	)		(16,901	)			(44,756	)		(34,542	)
Capitalized interest		279			159				499			269
Total other expense		(8,360	)		(5,380	)			(22,875	)		(11,508	)
INCOME BEFORE INCOME TAXES		50,480			70,749				66,133			141,685
INCOME TAXES		16,852			21,748				20,857			48,621
NET INCOME		33,628			49,001				45,276			93,064
Less:  Noncontrolling interest income		143			159				289			313
EARNINGS AVAILABLE TO PARENT	$	33,485		$	48,842			$	44,987		$	92,751
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	33,628		$	49,001			$	45,276		$	93,064
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		89,864			(3,994	)			95,602			(7,988	)
Change in unrealized gain on available-for-sale securities		728			(2,803	)			(1,981	)		(10,374	)
Other comprehensive income (loss)		90,592			(6,797	)			93,621			(18,362	)
Income tax expense (benefit) related to other comprehensive income		37,310			(2,564	)			37,839			(6,826	)
Other comprehensive income (loss), net of tax		53,282			(4,233	)			55,782			(11,536	)
COMPREHENSIVE INCOME		86,910			44,768				101,058			81,528
COMPREHENSIVE INCOME ATTRIBUTABLE
TO NONCONTROLLING INTEREST		143			159		��		289			313
COMPREHENSIVE INCOME AVAILABLE TO PARENT	$	86,767		$	44,609			$	100,769		$	81,215
The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part
of these statements.

61

OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,			December 31,
	2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	223,812		$	146,343
Receivables-
Customers (less accumulated provisions of $6,186,000 and $6,065,000, respectively,
for uncollectible accounts)		289,084			277,377
Associated companies		244,266			234,960
Other (less accumulated provisions of $99,000 and $7,000, respectively,
for uncollectible accounts)		12,970			14,492
Notes receivable from associated companies		172,061			222,861
Prepayments and other		19,027			5,452
		961,220			901,485
UTILITY PLANT:
In service		2,956,467			2,903,290
Less - Accumulated provision for depreciation		1,135,811			1,113,357
		1,820,656			1,789,933
Construction work in progress		37,385			37,766
		1,858,041			1,827,699
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies		193,071			256,974
Investment in lease obligation bonds		230,150			239,625
Nuclear plant decommissioning trusts		117,523			116,682
Other		97,807			100,792
		638,551			714,073
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		514,415			575,076
Property taxes		60,542			60,542
Unamortized sale and leaseback costs		37,629			40,130
Other		33,290			33,710
		645,876			709,458
	$	4,103,688		$	4,152,715
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	2,715		$	101,354
Short-term borrowings-
Associated companies		114,771			-
Other		1,386			1,540
Accounts payable-
Associated companies		78,944			131,725
Other		74,371			26,410
Accrued taxes		77,974			77,592
Accrued interest		25,709			25,673
Other		95,689			85,209
		471,559			449,503
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 175,000,000 shares -
60 shares outstanding		1,224,398			1,224,416
Accumulated other comprehensive loss		(128,603	)		(184,385	)
Retained earnings		174,010			254,023
Total common stockholder's equity		1,269,805			1,294,054
Noncontrolling interest		6,835			7,106
Total equity		1,276,640			1,301,160
Long-term debt and other long-term obligations		1,160,609			1,122,247
		2,437,249			2,423,407
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		681,972			653,475
Accumulated deferred investment tax credits		12,335			13,065
Asset retirement obligations		83,261			80,647
Retirement benefits		216,661			308,450
Other		200,651			224,168
		1,194,880			1,279,805
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	4,103,688		$	4,152,715
The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of
these balance sheets.

62

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30
	2009			2008
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	45,276		$	93,064
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		43,509			42,907
Amortization of regulatory assets, net		42,506			45,082
Purchased power cost recovery reconciliation		11,068			-
Amortization of lease costs		(4,540	)		(4,399	)
Deferred income taxes and investment tax credits, net		(11,252	)		7,059
Accrued compensation and retirement benefits		(4,593	)		(31,579	)
Accrued regulatory obligations		18,350			-
Electric service prepayment programs		(4,603	)		(21,771	)
Cash collateral from suppliers		6,380			-
Decrease (increase) in operating assets-
Receivables		(16,509	)		30,159
Prepayments and other current assets		(6,290	)		(2,485	)
Increase (decrease) in operating liabilities-
Accounts payable		(4,820	)		(6,831	)
Accrued taxes		(19,523	)		(31,306	)
Accrued interest		36			(1,252	)
Other		10,086			2,798
Net cash provided from operating activities		105,081			121,446
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		100,000			-
Short-term borrowings, net		114,617			69,573
Redemptions and Repayments-
Long-term debt		(100,984	)		(175,572	)
Dividend Payments-
Common stock		(125,000	)		(50,000	)
Other		(1,627	)		(445	)
Net cash used for financing activities		(12,994	)		(156,444	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(69,512	)		(92,061	)
Sales of investment securities held in trusts		24,941			79,613
Purchases of investment securities held in trusts		(30,877	)		(84,130	)
Loan repayments from associated companies, net		51,803			123,905
Cash investments		7,929			5,000
Other		1,098			2,828
Net cash provided from (used for) investing activities		(14,618	)		35,155
Net increase in cash and cash equivalents		77,469			157
Cash and cash equivalents at beginning of period		146,343			732
Cash and cash equivalents at end of period	$	223,812		$	889
The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral
part of these statements.

63

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. Until December 31, 2008, CEI purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that was reflected in rates approved by the PUCO. See Regulatory Matters – Ohio below for a discussion of Ohio power supply procurement issues for 2009 and beyond.

Results of Operations

CEI experienced a net loss of $58 million in the first six months of 2009 compared to net income of $125 million in the same period of 2008. The loss in 2009 resulted primarily from regulatory charges ($228 million) related to the implementation of CEI's ESP. The 2009 results were also adversely impacted by increased purchased power costs, partially offset by higher deferrals of new regulatory assets, increased revenues and lower other operating costs.

Revenues

Revenues increased by $53 million, or 6.1%, in the first six months of 2009 compared to the same period of 2008 primarily due to an increase in retail generation revenues ($81 million), partially offset by a decrease in distribution revenues ($19million) and other miscellaneous revenues ($9 million).

Retail generation revenues increased in the first six months of 2009 due to higher average unit prices in all customer classes and increased sales volume to residential and commercial customers, compared to the same period of 2008. Average prices increased due to an increase in CEI’s fuel cost recovery rider that was effective from January through May 2009, and effective June 1, 2009, the transmission tariff ended, with transmission services now included in the generation rate established under CEI's CBP. Reduced industrial KWH sales, principally to major automotive and steel customers, reflected weakened economic conditions. The increase in sales volumes for residential and commercial customers resulted from a decrease in customer shopping, as most of CEI’s customers returned to PLR service in December 2008 following the termination of certain government aggregation programs in CEI’s service territory.

Changes in retail generation sales and revenues in the first six months of 2009 compared to the same period in 2008 are summarized in the following tables:

	Increase
Retail Generation KWH Sales	(Decrease)
Residential		8.3 %
Commercial		14.6 %
Industrial		(8.6)%
Increase in Retail Generation Sales		2.0 %

Retail Generation Revenues	Increase
	(in millions)
Residential	$	27
Commercial		34
Industrial		20
Increase in Generation Revenues	$	81

Revenues from distribution throughput decreased by $19 million in the first six months of 2009 compared to the same period of 2008 due to a decrease in KWH deliveries, partially offset by higher average unit prices in the commercial and industrial sectors. The higher average unit prices was the net result of a PUCO-approved distribution rate increase effective May 1, 2009,  partially offset by reduced transition rates (see Regulatory Matters – Ohio). The lower KWH deliveries in the first six months of 2009 were due to economic conditions. Cooling degree days in the first six months of 2009 were 17% lower than in the previous year, while heating degree days increased slightly.

64

Changes in distribution KWH deliveries and revenues in the first six months of 2009 compared to the same period of 2008 are summarized in the following tables.

Distribution KWH Deliveries	Decrease
Residential		(0.5) %
Commercial		(3.6) %
Industrial		(19.1) %
Decrease in Distribution Deliveries		(9.8) %

Distribution Revenues	Decrease
	(In millions)
Residential	$	(10	)
Commercial		(3	)
Industrial		(6	)
Decrease in Distribution Revenues	$	(19	)

Expenses

Total expenses increased by $333 million in the first six months of 2009 compared to the same period of 2008. The following table presents the change from the prior year by expense category:

Expenses  - Changes	Increase (Decrease)
	(in millions)
Purchased power costs	$	225
Other operating costs		(24	)
Amortization of regulatory assets		209
Deferral of new regulatory assets		(79	)
General Taxes		2
Net Increase in Expenses	$	333

Higher purchased power costs reflect the results of CEI’s power procurement process for retail customers in the first six months of 2009 (see Regulatory Matters – Ohio). Increased amortization of regulatory assets was primarily due to the impairment of CEI’s Extended RTC balance ($216 million) in accordance with the PUCO-approved ESP. The increase in the deferral of new regulatory assets was due to CEI’s deferral of purchased power costs as approved by the PUCO, partially offset by lower deferred MISO transmission expenses and the absence of RCP distribution deferrals that ceased at the end of 2008. Other operating costs were $24 million lower than in the previous year due to lower transmission expenses (included in the cost of power purchased from others beginning June 1, 2009) and reduced labor and contractor costs, partially offset by costs associated with the ESP for economic development and energy efficiency programs, higher pension expense and restructuring costs. The increase in general taxes was primarily due to higher property taxes.

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.

65

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, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2009 and 2008 and the consolidated statement of cash flows for the six-month periods ended June 30, 2009 and 2008. 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, 2008, 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 24, 2009, we expressed an unqualified opinion on those consolidated financial statements.  As discussed in Note 6 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest.  The accompanying December 31, 2008 consolidated balance sheet reflects this change.

PricewaterhouseCoopers LLP

Cleveland, Ohio

August 3, 2009

66

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30						June 30
	2009			2008			2009			2008
STATEMENTS OF INCOME	(In thousands)
REVENUES:
Electric sales	$	458,287		$	418,194		$	889,692		$	836,902
Excise tax collections		16,799			16,195			35,119			34,795
Total revenues		475,086			434,389			924,811			871,697
EXPENSES:
Purchased power from affiliates		243,499			185,483			482,371			375,679
Purchased power from non-affiliates		49,414			128			121,160			3,176
Other operating costs		39,177			62,659			104,007			127,777
Provision for depreciation		17,852			17,744			36,132			36,820
Amortization of regulatory assets		29,580			38,525			286,317			76,781
Deferral of new regulatory assets		(39,771	)		(26,019	)		(134,587	)		(55,267	)
General taxes		36,856			32,425			74,997			72,508
Total expenses		376,607			310,945			970,397			637,474
OPERATING INCOME (LOSS)		98,479			123,444			(45,586	)		234,223
OTHER INCOME (EXPENSE):
Investment income		7,614			8,394			16,034			17,582
Miscellaneous income (expense)		798			(280	)		2,792			838
Interest expense		(32,757	)		(30,935	)		(66,079	)		(63,455	)
Capitalized interest		51			188			118			384
Total other expense		(24,294	)		(22,633	)		(47,135	)		(44,651	)
INCOME (LOSS) BEFORE INCOME TAXES		74,185			100,811			(92,721	)		189,572
INCOME TAX EXPENSE (BENEFIT)		26,461			33,779			(35,045	)		64,105
NET INCOME (LOSS)		47,724			67,032			(57,676	)		125,467
Less:  Noncontrolling interest income		419			459			877			1,043
EARNINGS (LOSS) AVAILABLE TO PARENT	$	47,305		$	66,573		$	(58,553	)	$	124,424
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME (LOSS)	$	47,724		$	67,032		$	(57,676	)	$	125,467
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		43,903			(213	)		47,870			(426	)
Income tax expense (benefit) related to other comprehensive income		17,936			(390	)		19,306			(109	)
Other comprehensive income (loss), net of tax		25,967			177			28,564			(317	)
COMPREHENSIVE INCOME (LOSS)		73,691			67,209			(29,112	)		125,150
COMPREHENSIVE INCOME ATTRIBUTABLE
TO NONCONTROLLING INTEREST		419			459			877			1,043
COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT	$	73,272		$	66,750		$	(29,989	)	$	124,107
The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an
integral part of these statements.

67

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,				December 31,
		2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	230		$	226
Receivables-
Customers (less accumulated provisions of $6,252,000 and
$5,916,000, respectively, for uncollectible accounts)			317,526			276,400
Associated companies			158,425			113,182
Other			11,934			13,834
Notes receivable from associated companies			24,510			19,060
Prepayments and other			3,933			2,787
			516,558			425,489
UTILITY PLANT:
In service			2,258,897			2,221,660
Less - Accumulated provision for depreciation			870,038			846,233
			1,388,859			1,375,427
Construction work in progress			40,553			40,651
			1,429,412			1,416,078
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes			388,645			425,715
Other			10,227			10,249
			398,872			435,964
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill			1,688,521			1,688,521
Regulatory assets			628,068			783,964
Property taxes			71,500			71,500
Other			10,343			10,818
			2,398,432			2,554,803
		$	4,743,274		$	4,832,334
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt		$	150,721		$	150,688
Short-term borrowings-
Associated companies			293,574			227,949
Accounts payable-
Associated companies			61,603			106,074
Other			45,657			7,195
Accrued taxes			63,500			87,810
Accrued interest			14,165			13,932
Other			47,890			40,095
			677,110			633,743
CAPITALIZATION:
Common stockholder's equity
Common stock, without par value, authorized 105,000,000 shares -
67,930,743 shares outstanding			878,735			878,785
Accumulated other comprehensive loss			(106,293	)		(134,857	)
Retained earnings			801,401			859,954
Total common stockholder's equity			1,573,843			1,603,882
Noncontrolling interest			20,592			22,555
Total equity			1,594,435			1,626,437
Long-term debt and other long-term obligations			1,573,094			1,591,586
			3,167,529			3,218,023
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			665,370			704,270
Accumulated deferred investment tax credits			12,433			13,030
Retirement benefits			90,331			128,738
Lease assignment payable to associated companies			40,827			40,827
Other			89,674			93,703
			898,635			980,568
COMMITMENTS AND CONTINGENCIES (Note 8)
		$	4,743,274		$	4,832,334
The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating
Company are an integral part of these balance sheets.

68

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30
	2009			2008
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(57,676	)	$	125,467
Adjustments to reconcile net income (loss) to net cash from operating activities-
Provision for depreciation		36,132			36,820
Amortization of regulatory assets		286,317			76,781
Deferral of new regulatory assets		(134,587	)		(55,267	)
Purchased power cost recovery reconciliation		2,072			-
Deferred income taxes and investment tax credits, net		(58,506	)		(12,125	)
Accrued compensation and retirement benefits		2,092			(4,027	)
Accrued regulatory obligations		12,057			-
Electric service prepayment programs		(3,510	)		(11,498	)
Cash collateral from suppliers		5,365			-
Decrease (increase) in operating assets-
Receivables		(84,469	)		73,484
Prepayments and other current assets		(1,145	)		(689	)
Increase (decrease) in operating liabilities-
Accounts payable		18,991			11,076
Accrued taxes		(29,434	)		(38,654	)
Accrued interest		232			178
Other		3,265			4,203
Net cash provided from (used for) operating activities		(2,804	)		205,749
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		47,423			-
Redemptions and Repayments-
Long-term debt		(368	)		(335	)
Short-term borrowings, net		-			(100,562	)
Dividend Payments-
Common stock		(25,000	)		(100,000	)
Other		(3,019	)		(2,955	)
Net cash provided from (used for) financing activities		19,036			(203,852	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(46,434	)		(67,206	)
Loan repayments from (loans to) associated companies, net		(5,449	)		30,132
Redemption of lessor notes		37,070			37,712
Other		(1,415	)		(2,528	)
Net cash used for investing activities		(16,228	)		(1,890	)
Net increase in cash and cash equivalents		4			7
Cash and cash equivalents at beginning of period		226			232
Cash and cash equivalents at end of period	$	230		$	239
The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company
are an integral part of these statements.

69

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. Until December 31, 2008, TE purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that was reflected in rates approved by the PUCO. See Regulatory Matters – Ohio below for a discussion of Ohio power supply procurement issues for 2009 and beyond.

Results of Operations

Net income in the first six months of 2009 decreased to $7million from $38million in the same period of 2008. The decrease resulted primarily from the completion of transition cost recovery in 2008.

Revenues

Revenues increased $38million, or 8.7%, in the first six months of 2009 compared to the same period of 2008 primarily due to increased retail generation revenues ($117million), partially offset by lower distribution revenues ($70million) and wholesale generation revenues ($11 million).

Retail generation revenues increased in the first six months of 2009 due to higher average prices across all customer classes and increased KWH sales to residential and commercial customers, compared to the same period of 2008. Average prices increased primarily due to an increase in TE's fuel cost recovery rider that was effective from January through May 2009. Effective June 1, 2009, the transmission tariff ended and the recovery of transmission costs is included in the generation rate established under TE’s CBP. Reduced industrial KWH sales, principally to major automotive and steel customers, reflected weakened economic conditions. The increase in sales volume for residential and commercial customers resulted from a decrease in customer shopping. Most of TE’s customers returned to PLR service in December 2008, following the termination of certain government aggregation programs in TE’s service territory.

The decrease in wholesale revenues was due to the expiration of a sales agreement with AMP-Ohio at the end of 2008 ($6 million) and lower revenues from associated company sales to NGC ($5 million) from TE’s leasehold interest in Beaver Valley Unit 2.

Changes in retail electric generation KWH sales and revenues in the first six months of 2009 from the same period of 2008 are summarized in the following tables.

	Increase
Retail Generation KWH Sales	(Decrease)
Residential		8.1	%
Commercial		39.1	%
Industrial		(13.5	)%
Net Increase in Retail Generation Sales		2.6	%

Retail Generation Revenues	Increase
	(In millions)
Residential	$	28
Commercial		51
Industrial		38
Increase in Retail Generation Revenues	$	117

Revenues from distribution throughput decreased by $70 million in the first six months of 2009 compared to the same period of 2008 due to lower average unit prices and lower KWH deliveries for all customer classes due primarily to economic conditions. Transition charges that ceased effective January 1, 2009, with the full recovery of related costs, were partially offset by a PUCO-approved distribution rate increase (see Regulatory Matters – Ohio).

70

Decreases in distribution KWH deliveries and revenues in the first six months of 2009 from the same period of 2008 are summarized in the following tables.

Distribution KWH Deliveries	Decrease
Residential		(2.0	)%
Commercial		(8.7	)%
Industrial		(15.7	)%
Decrease in Distribution Deliveries		(10.5	)%

Distribution Revenues	Decrease
	(In millions)
Residential	$	(14	)
Commercial		(35	)
Industrial		(21	)
Decrease in Distribution Revenues	$	(70	)

Expenses

Total expenses increased $83 million in the first six months of 2009 from the same period of 2008. The following table presents changes from the prior year by expense category.

Expenses – Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	111
Other operating costs		(16	)
Provision for depreciation		(2	)
Amortization of regulatory assets, net		(10	)
Net Increase in Expenses	$	83

Higher purchased power costs reflect the results of TE’s power procurement process for retail customers in the first six months of 2009 (see Regulatory Matters – Ohio). Other operating costs decreased primarily due to reduced transmission expenses (included in the cost of power purchased from others beginning June 1, 2009) and lower costs associated with TE’s leasehold interest in Beaver Valley Unit 2 (absence of a refueling outage in the 2009 period). These reductions were partially offset by cost increases associated with regulatory obligations for economic development and energy efficiency programs. Depreciation expense decreased due to the transfer of leasehold improvements for the Bruce Mansfield Plant and Beaver Valley Unit 2 to FGCO and NGC, respectively, during 2008. The decrease in the net amortization of regulatory assets is primarily due to the completion of transition cost recovery, partially offset by a reduction in transmission cost deferrals and the absence of RCP distribution cost deferrals in 2009.

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.

.

71

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, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2009 and 2008 and the consolidated statement of cash flows for the six-month periods ended June 30, 2009 and 2008. 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, 2008, 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 24, 2009, we expressed an unqualified opinion on those consolidated financial statements.  As discussed in Note 6 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest.  The accompanying December 31, 2008 consolidated balance sheet reflects this change.

PricewaterhouseCoopers LLP

Cleveland, Ohio

August 3, 2009

72

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30						June 30
	2009			2008			2009			2008
	(In thousands)
STATEMENTS OF INCOME
REVENUES:
Electric sales	$	219,911		$	214,353		$	456,996		$	418,022
Excise tax collections		6,297			7,153			14,026			15,178
Total revenues		226,208			221,506			471,022			433,200
EXPENSES:
Purchased power from affiliates		130,564			102,773			255,888			202,267
Purchased power from non-affiliates		18,244			77			58,781			1,881
Other operating costs		35,480			50,805			80,484			96,134
Provision for depreciation		7,717			7,941			15,289			16,966
Amortization of regulatory assets, net		11,771			16,431			21,668			31,962
General taxes		12,349			12,605			26,599			26,982
Total expenses		216,125			190,632			458,709			376,192
OPERATING INCOME		10,083			30,874			12,313			57,008
OTHER INCOME (EXPENSE):
Investment income		7,529			5,224			13,013			11,705
Miscellaneous income (expense)		1,375			(1,947	)		35			(3,459	)
Interest expense		(9,262	)		(5,578	)		(14,795	)		(11,613	)
Capitalized interest		50			88			92			125
Total other expense		(308	)		(2,213	)		(1,655	)		(3,242	)
INCOME BEFORE INCOME TAXES		9,775			28,661			10,658			53,766
INCOME TAXES		3,370			7,352			3,261			15,440
NET INCOME		6,405			21,309			7,397			38,326
Less:  Noncontrolling interest income		1			2			3			4
EARNINGS AVAILABLE TO PARENT	$	6,404		$	21,307		$	7,394		$	38,322
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	6,405		$	21,309		$	7,397		$	38,326
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		19,016			(64	)		19,149			(127	)
Change in unrealized gain on available-for-sale securities		(2,739	)		(2,481	)		(3,548	)		(520	)
Other comprehensive income (loss)		16,277			(2,545	)		15,601			(647	)
Income tax expense (benefit) related to other comprehensive income		7,224			(914	)		7,205			(186	)
Other comprehensive income (loss), net of tax		9,053			(1,631	)		8,396			(461	)
COMPREHENSIVE INCOME		15,458			19,678			15,793			37,865
COMPREHENSIVE INCOME ATTRIBUTABLE
TO NONCONTROLLING INTEREST		1			2			3			4
COMPREHENSIVE INCOME AVAILABLE TO PARENT	$	15,457		$	19,676		$	15,790		$	37,861
The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of
these statements.

73

THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,				December 31,
		2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	319,454		$	14
Receivables-
Customers			508			751
Associated companies			64,734			61,854
Other (less accumulated provisions of $192,000 and $203,000,
respectively, for uncollectible accounts)			19,978			23,336
Notes receivable from associated companies			131,556			111,579
Prepayments and other			5,193			1,213
			541,423			198,747
UTILITY PLANT:
In service			891,108			870,911
Less - Accumulated provision for depreciation			417,418			407,859
			473,690			463,052
Construction work in progress			8,065			9,007
			481,755			472,059
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes			124,357			142,687
Long-term notes receivable from associated companies			37,075			37,233
Nuclear plant decommissioning trusts			73,696			73,500
Other			1,625			1,668
			236,753			255,088
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill			500,576			500,576
Regulatory assets			91,407			109,364
Property taxes			22,970			22,970
Other			66,161			51,315
			681,114			684,225
		$	1,941,045		$	1,610,119
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt		$	222		$	34
Accounts payable-
Associated companies			31,622			70,455
Other			24,178			4,812
Notes payable to associated companies			171,180			111,242
Accrued taxes			25,777			24,433
Lease market valuation liability			36,900			36,900
Other			23,311			22,489
			313,190			270,365
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			175,883			175,879
Accumulated other comprehensive loss			(24,976	)		(33,372	)
Retained earnings			197,927			190,533
Total common stockholder's equity			495,844			480,050
Noncontrolling interest			2,678			2,675
Total equity			498,522			482,725
Long-term debt and other long-term obligations			600,430			299,626
			1,098,952			782,351
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			85,343			78,905
Accumulated deferred investment tax credits			6,585			6,804
Lease market valuation liability			254,650			273,100
Retirement benefits			57,734			73,106
Asset retirement obligations			31,234			30,213
Lease assignment payable to associated companies			30,529			30,529
Other			62,828			64,746
			528,903			557,403
COMMITMENTS AND CONTINGENCIES (Note 8)
		$	1,941,045		$	1,610,119
The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an
integral part of these balance sheets.

74

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30
	2009			2008
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	7,397		$	38,326
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		15,289			16,966
Amortization of regulatory assets, net		21,668			31,962
Purchased power cost recovery reconciliation		(4,197	)		-
Deferred rents and lease market valuation liability		(40,697	)		(39,045	)
Deferred income taxes and investment tax credits, net		(1,206	)		(3,113	)
Accrued compensation and retirement benefits		711			(1,160	)
Accrued regulatory obligations		4,450			-
Electric service prepayment programs		(1,458	)		(6,017	)
Cash collateral from suppliers		2,755			-
Decrease (increase) in operating assets-
Receivables		1,075			76,978
Prepayments and other current assets		(220	)		(292	)
Increase (decrease) in operating liabilities-
Accounts payable		5,533			(166,120	)
Accrued taxes		(2,936	)		(7,923	)
Accrued interest		3,983			-
Other		1,788			866
Net cash provided from (used for) operating activities		13,935			(58,572	)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		297,422			-
Short-term borrowings, net		59,938			21,558
Redemptions and Repayments-
Long-term debt		(236	)		(17	)
Dividend Payments-
Common stock		(25,000	)		(35,000	)
Other		(247	)		-
Net cash provided from (used for) financing activities		331,877			(13,459	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(21,661	)		(34,388	)
Loan repayments from (loans to) associated companies, net		(19,819	)		97,614
Redemption of lessor notes		18,330			11,959
Sales of investment securities held in trusts		77,323			21,791
Purchases of investment securities held in trusts		(78,700	)		(23,581	)
Other		(1,845	)		(1,364	)
Net cash provided from (used for) investing activities		(26,372	)		72,031
Net change in cash and cash equivalents		319,440			-
Cash and cash equivalents at beginning of period		14			22
Cash and cash equivalents at end of period	$	319,454		$	22
The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an
integral part of these statements.

75

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 franchise customers electing to retain JCP&L as their power supplier. JCP&L procures electric supply to serve its BGS customers through a statewide auction process approved by the NJBPU.

Results of Operations

Net income for the first six months of 2009 decreased to $66million from $77million in the same period in 2008. The decrease was primarily due to lower revenues, partially offset by lower purchased power costs and reduced amortization of regulatory assets.

Revenues

In the first six months of 2009, revenues decreased by $147 million, or 9%, compared with the same period of 2008. Retail and wholesale generation revenues decreased by $3million and $124million, respectively, and distribution revenues decreased by $14 million in the first six months of 2009.

Retail generation revenues decreased due to lower retail generation KWH sales in all sectors, partially offset by higher unit prices in the residential and commercial sectors resulting from the BGS auctions effective June 1, 2008, and June 1, 2009. Lower sales to the residential sector reflected milder weather in JCP&L’s service territory, while the decrease in sales to the commercial sector was primarily due to an increase in the number of shopping customers. Industrial sales were lower as a result of weakened economic conditions.

Wholesale generation revenues decreased $124million in the first six months of 2009 due to lower market prices and a decrease in sales volume from NUG purchases resulting from the termination of a NUG contract in October 2008.

Changes in retail generation KWH sales and revenues by customer class in the first six months of 2009 compared to the same period of 2008 are summarized in the following tables:

Retail Generation KWH Sales	Decrease
Residential		(3.5)	%
Commercial		(13.6)	%
Industrial		(6.6)	%
Decrease in Generation Sales		(7.7)	%

Retail Generation Revenues	Increase (Decrease)
	(In millions)
Residential	$	29
Commercial		(27	)
Industrial		(5	)
Net Decrease in Generation Revenues	$	(3	)

Distribution revenues decreased $14 million in the first six months of 2009 compared to the same period of 2008 due to lower KWH deliveries, reflecting weather and economic impacts in JCP&L’s service territory, partially offset by an increase in composite unit prices.

76

Changes in distribution KWH deliveries and revenues by customer class in the first six months of 2009 compared to the same period in 2008 are summarized in the following tables:

Distribution KWH Deliveries	Decrease
Residential		(3.5)	%
Commercial		(3.3)	%
Industrial		(12.6)	%
Decrease in Distribution Deliveries		(4.6)	%

Distribution Revenues	Decrease
	(In millions)
Residential	$	(8	)
Commercial		(5	)
Industrial		(1	)
Decrease in Distribution Revenues	$	(14	)

Expenses

Total expenses decreased by $135 million in the first six months of 2009 compared to the same period of 2008. The following table presents changes from the prior year period by expense category:

Expenses  - Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	(126	)
Provision for depreciation		4
Amortization of regulatory assets		(11	)
General taxes		(2	)
Net decrease in expenses	$	(135	)

Purchased power costs decreased in the first six months of 2009 primarily due to the lower KWH sales requirements discussed above, partially offset by higher unit prices resulting from the BGS auction process. Depreciation expense increased due to an increase in depreciable property since the second quarter of 2008. Amortization of regulatory assets decreased in the first six months of 2009 primarily due to the full recovery of certain regulatory assets in June 2008.  General taxes decreased principally as the result of lower sales taxes.

Other Expenses

Other expenses increased by $7million in the first six months of 2009 compared to the same period in 2008 primarily due to higher interest expense associated with JCP&L's $300 million Senior Notes issuance in January 2009.

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, as approved by an earlier order from the NJBPU. The New Jersey Rate Counsel appealed the sale to the Appellate Division of the Superior Court of New Jersey.  On July 10, 2009, the Court upheld the NJBPU’s order and the sale of the plant.

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.

77

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, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2009 and 2008 and the consolidated statement of cash flows for the six-month periods ended June 30, 2009 and 2008. 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, 2008, 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 24, 2009, 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, 2008, 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 3, 2009

78

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30						June 30
	2009			2008			2009			2008
	(In thousands)
REVENUES:
Electric sales	$	697,061		$	823,104		$	1,457,981		$	1,604,537
Excise tax collections		11,031			11,639			23,762			24,434
Total revenues		708,092			834,743			1,481,743			1,628,971
EXPENSES:
Purchased power		423,950			534,177			905,191			1,030,858
Other operating costs		70,876			77,569			156,746			156,353
Provision for depreciation		25,301			23,543			50,404			46,825
Amortization of regulatory assets		80,018			86,507			166,849			178,026
General taxes		12,587			15,538			30,083			32,566
Total expenses		612,732			737,334			1,309,273			1,444,628
OPERATING INCOME		95,360			97,409			172,470			184,343
OTHER INCOME (EXPENSE):
Miscellaneous income		2,007			1,413			2,812			1,024
Interest expense		(29,671	)		(24,840	)		(57,539	)		(49,304	)
Capitalized interest		218			430			280			706
Total other expense		(27,446	)		(22,997	)		(54,447	)		(47,574	)
INCOME BEFORE INCOME TAXES		67,914			74,412			118,023			136,769
INCOME TAXES		29,848			31,468			52,399			59,871
NET INCOME		38,066			42,944			65,624			76,898
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		20,918			(3,449	)		25,039			(6,898	)
Unrealized gain on derivative hedges		69			69			138			138
Other comprehensive income (loss)		20,987			(3,380	)		25,177			(6,760	)
Income tax expense (benefit) related to other comprehensive income		11,059			(1,469	)		12,489			(2,939	)
Other comprehensive income (loss), net of tax		9,928			(1,911	)		12,688			(3,821	)
TOTAL COMPREHENSIVE INCOME	$	47,994		$	41,033		$	78,312		$	73,077
The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an
integral part of these statements.

79

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,			December 31,
	2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	138		$	66
Receivables-
Customers (less accumulated provisions of $3,158,000 and $3,230,000
respectively, for uncollectible accounts)		315,553			340,485
Associated companies		166			265
Other		21,337			37,534
Notes receivable - associated companies		17,595			16,254
Prepaid taxes		156,503			10,492
Other		17,598			18,066
		528,890			423,162
UTILITY PLANT:
In service		4,386,758			4,307,556
Less - Accumulated provision for depreciation		1,582,136			1,551,290
		2,804,622			2,756,266
Construction work in progress		57,080			77,317
		2,861,702			2,833,583
OTHER PROPERTY AND INVESTMENTS:
Nuclear fuel disposal trust		192,585			181,468
Nuclear plant decommissioning trusts		146,098			143,027
Other		2,163			2,145
		340,846			326,640
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		1,810,936			1,810,936
Regulatory assets		1,055,327			1,228,061
Other		24,978			29,946
		2,891,241			3,068,943
	$	6,622,679		$	6,652,328
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	29,831		$	29,094
Short-term borrowings-
Associated companies		65,113			121,380
Accounts payable-
Associated companies		14,863			12,821
Other		177,379			198,742
Accrued taxes		7,258			20,561
Accrued interest		18,570			9,197
Other		108,311			133,091
		421,325			524,886
CAPITALIZATION
Common stockholder's equity-
Common stock, $10 par value, authorized 16,000,000 shares-
13,628,447 shares outstanding		136,284			144,216
Other paid-in capital		2,502,675			2,644,756
Accumulated other comprehensive loss		(203,850	)		(216,538	)
Retained earnings		134,200			156,576
Total common stockholder's equity		2,569,309			2,729,010
Long-term debt and other long-term obligations		1,817,960			1,531,840
		4,387,269			4,260,850
NONCURRENT LIABILITIES:
Power purchase contract liability		474,533			531,686
Accumulated deferred income taxes		680,159			689,065
Nuclear fuel disposal costs		196,357			196,235
Asset retirement obligations		98,365			95,216
Retirement benefits		172,668			190,182
Other		192,003			164,208
		1,814,085			1,866,592
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	6,622,679		$	6,652,328
The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral
part of these balance sheets.

80

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30
	2009			2008
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	65,624		$	76,898
Adjustments to reconcile net income to net cash from operating activities -
Provision for depreciation		50,404			46,825
Amortization of regulatory assets		166,849			178,026
Deferred purchased power and other costs		(50,542	)		(69,247	)
Deferred income taxes and investment tax credits, net		3,440			(8,656	)
Accrued compensation and retirement benefits		(2,883	)		(28,695	)
Cash collateral received from (returned to) suppliers		(209	)		66,040
Decrease (increase) in operating assets-
Receivables		41,228			(79,001	)
Prepaid taxes		(146,011	)		(137,006	)
Other current assets		271			534
Increase (decrease) in operating liabilities-
Accounts payable		(19,321	)		96,297
Accrued taxes		(14,007	)		(1,972	)
Accrued interest		9,373			(54	)
Tax collections payable		(9,714	)		(12,493	)
Other		4,555			(14,194	)
Net cash provided from operating activities		99,057			113,302
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		299,619			-
Short-term borrowings, net		-			164,358
Redemptions and Repayments-
Long-term debt		(13,093	)		(12,012	)
Common Stock		(150,000	)		-
Short-term borrowings, net		(56,267	)		-
Dividend Payments-
Common stock		(88,000	)		(176,000	)
Other		(2,260	)		(67	)
Net cash used for financing activities		(10,001	)		(23,721	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(78,401	)		(98,068	)
Proceeds from asset sales		-			20,000
Loans to associated companies, net		(1,341	)		(653	)
Sales of investment securities held in trusts		244,880			113,970
Purchases of investment securities held in trusts		(252,856	)		(122,324	)
Other		(1,266	)		(2,368	)
Net cash used for investing activities		(88,984	)		(89,443	)
Net increase in cash and cash equivalents		72			138
Cash and cash equivalents at beginning of period		66			94
Cash and cash equivalents at end of period	$	138		$	232
The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company
are an integral part of these statements.

81

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. Met-Ed has a partial requirements wholesale power sales agreement with FES, to supply a portion of each of its default service obligations at fixed prices through 2009. This sales agreement is renewed annually unless cancelled by either party with at least a sixty day written notice prior to the end of the calendar year.

Results of Operations

Net income decreased to $27 million in the first six months of 2009, compared to $42million in the same period of 2008. The decrease was primarily due to increased amortization of regulatory assets, partially offset by higher revenues and lower other operating costs.

Revenues

Revenues increased by $15 million, or 1.9%, in the first six months of 2009, compared to the same period of 2008, primarily due to higher distribution throughput revenues, partially offset by a decrease in retail generation and wholesale revenues. Wholesale revenues decreased by $1million in the first six months of 2009 due to lower wholesale KWH sales volume, partially offset by higher capacity prices for PJM market participants.

In the first six months of 2009, retail generation revenues decreased $17 million due to lower KWH sales to all classes with a slight increase in composite unit prices in all customer classes. Lower KWH sales to commercial and industrial customers were principally due to economic conditions in Met-Ed’s service territory. Lower KWH sales in the residential sector were due to decreased weather-related usage, reflecting a 22.5% decrease in cooling degree days in the first six months of 2009 and a 2.5% decrease in heating degree days in the second quarter of 2009.

Changes in retail generation sales and revenues in the first six months of 2009 compared to the same period of 2008 are summarized in the following tables:

Retail Generation KWH Sales	(Decrease)
Residential		(0.2	)%
Commercial		(4.3	)%
Industrial		(13.6	)%
Decrease in Retail Generation Sales		(5.3	)%

Retail Generation Revenues	(Decrease)
	(In millions)
Residential	$	-
Commercial		(5	)
Industrial		(12	)
Decrease in Retail Generation Revenues	$	(17	)

In the first six months of 2009, distribution throughput revenues increased $38million primarily due to higher transmission rates, resulting from the annual updates to Met-Ed’s TSC rider in June 2008 and 2009. Decreased deliveries to commercial and industrial customers reflected the weakened economy, while decreased deliveries to residential customers were a result of the weather conditions described above.

82

Changes in distribution KWH deliveries and revenues in the first six months of 2009 compared to the same period of 2008 are summarized in the following tables:

Distribution KWH Deliveries	(Decrease)
Residential		(0.2	)%
Commercial		(4.3	)%
Industrial		(13.6	)%
Decrease in Distribution Deliveries		(5.3	)%

Distribution Revenues	Increase
	(In millions)
Residential	$	22
Commercial		11
Industrial		5
Increase in Distribution Revenues	$	38

PJM transmission service revenues decreased by $5million in the first six months of 2009 compared to the same period of 2008, primarily due to decreased revenues related to Met-Ed’s Financial Transmission Rights. Met-Ed defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.

Operating Expenses

Total operating expenses increased by $33 million in the first six months of 2009 compared to the same period of 2008. The following table presents changes from the prior year by expense category:

Expenses – Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	(9	)
Other operating costs		(66	)
Provision for depreciation		3
Amortization of regulatory assets, net		103
General taxes		2
Net Increase in Expenses	$	33

The net amortization of regulatory assets increased by $103 million in the first six months of 2009 compared to the same period of 2008 primarily due to increased transmission cost recovery reflecting lower PJM transmission service expenses and the increased transmission revenues described above. Other operating costs decreased $66 million in the first six months of 2009 primarily due to lower transmission expenses as a result of decreased congestion costs and transmission loss expenses. Purchased power costs decreased by $9 million, or 2.0%, in the first six months of 2009 due to reduced volume as a result of lower KWH sales requirements, partially offset by an increase in composite unit prices. Depreciation expense increased primarily due to an increase in depreciable property since the second quarter of 2008.

Other Expense

Other expense increased in the first six months of 2009 primarily due to a decrease in interest earned on regulatory assets, reflecting a lower regulatory asset base, and an increase in interest expense from Met-Ed’s $300 million Senior Notes issuance in January 2009.

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.

83

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 subsidiary as of June 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2009 and 2008 and the consolidated statement of cash flows for the six-month periods ended June 30, 2009 and 2008. 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, 2008, 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 24, 2009, 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, 2008, 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 3, 2009

84

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30						June 30
	2009			2008			2009			2008
	(In thousands)
REVENUES:
Electric sales	$	360,022		$	373,821		$	769,708		$	753,429
Gross receipts tax collections		17,586			18,158			37,569			38,876
Total revenues		377,608			391,979			807,277			792,305
EXPENSES:
Purchased power from affiliates		78,652			68,209			178,729			151,651
Purchased power from non-affiliates		123,299			149,534			247,210			283,074
Other operating costs		51,309			117,028			157,666			224,045
Provision for depreciation		12,919			10,940			25,058			22,052
Amortization (deferral) of regulatory assets, net		61,548			(11,645	)		89,139			(13,842	)
General taxes		22,034			20,076			43,969			41,857
Total expenses		349,761			354,142			741,771			708,837
OPERATING INCOME		27,847			37,837			65,506			83,468
OTHER INCOME (EXPENSE):
Interest income		2,769			4,873			5,955			10,352
Miscellaneous income		1,058			789			1,914			480
Interest expense		(14,763	)		(10,980	)		(28,122	)		(22,652	)
Capitalized interest		62			199			77			(20	)
Total other expense		(10,874	)		(5,119	)		(20,176	)		(11,840	)
INCOME BEFORE INCOME TAXES		16,973			32,718			45,330			71,628
INCOME TAXES		6,968			12,921			18,703			29,596
NET INCOME		10,005			19,797			26,627			42,032
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		27,369			(2,233	)		31,922			(4,466	)
Unrealized gain on derivative hedges		84			84			168			168
Other comprehensive income (loss)		27,453			(2,149	)		32,090			(4,298	)
Income tax expense (benefit) related to other comprehensive income		13,592			(971	)		15,385			(1,941	)
Other comprehensive income (loss), net of tax		13,861			(1,178	)		16,705			(2,357	)
TOTAL COMPREHENSIVE INCOME	$	23,866		$	18,619		$	43,332		$	39,675
The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral
part of these statements.

85

METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,			December 31,
	2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	125		$	144
Receivables-
Customers (less accumulated provisions of $3,421,000 and $3,616,000,
respectively, for uncollectible accounts)		163,556			159,975
Associated companies		20,145			17,034
Other		12,387			19,828
Notes receivable from associated companies		317,894			11,446
Prepaid taxes		46,403			6,121
Other		4,595			1,621
		565,105			216,169
UTILITY PLANT:
In service		2,116,595			2,065,847
Less - Accumulated provision for depreciation		794,738			779,692
		1,321,857			1,286,155
Construction work in progress		17,763			32,305
		1,339,620			1,318,460
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		233,289			226,139
Other		976			976
		234,265			227,115
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		416,499			416,499
Regulatory assets		496,902			412,994
Power purchase contract asset		183,639			300,141
Other		34,308			31,031
		1,131,348			1,160,665
	$	3,270,338		$	2,922,409
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	128,500		$	28,500
Short-term borrowings-
Associated companies		-			15,003
Other		250,000			250,000
Accounts payable-
Associated companies		29,094			28,707
Other		36,319			55,330
Accrued taxes		14,484			16,238
Accrued interest		16,985			6,755
Other		27,754			30,647
		503,136			431,180
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 900,000 shares-
859,500 shares outstanding		1,196,136			1,196,172
Accumulated other comprehensive loss		(124,279	)		(140,984	)
Accumulated deficit		(24,496	)		(51,124	)
Total common stockholder's equity		1,047,361			1,004,064
Long-term debt and other long-term obligations		713,812			513,752
		1,761,173			1,517,816
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		429,032			387,757
Accumulated deferred investment tax credits		7,540			7,767
Nuclear fuel disposal costs		44,356			44,328
Asset retirement obligations		174,424			170,999
Retirement benefits		121,326			145,218
Power purchase contract liability		161,106			150,324
Other		68,245			67,020
		1,006,029			973,413
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	3,270,338		$	2,922,409
The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral
part of these balance sheets.

86

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30
	2009			2008
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	26,627		$	42,032
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		25,058			22,052
Amortization (deferral) of regulatory assets, net		89,139			(13,842	)
Deferred costs recoverable as regulatory assets		(47,592	)		(12,468	)
Deferred income taxes and investment tax credits, net		30,135			29,113
Accrued compensation and retirement benefits		3,250			(14,819	)
Cash collateral		(6,800	)		-
Decrease (Increase) in operating assets-
Receivables		346			(31,840	)
Prepayments and other current assets		(39,068	)		(25,316	)
Increase (decrease) in operating liabilities-
Accounts payable		(18,624	)		7,411
Accrued taxes		(1,754	)		(14,451	)
Accrued interest		10,230			31
Other		7,870			7,608
Net cash provided from (used for) operating activities		78,817			(4,489	)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		300,000			28,500
Short-term borrowings, net		-			72,485
Redemptions and Repayments-
Long-term debt		-			(28,637	)
Short-term borrowings, net		(15,003	)		-
Other		(2,267	)		-
Net cash provided from financing activities		282,730			72,348
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(48,464	)		(62,011	)
Sales of investment securities held in trusts		63,086			81,538
Purchases of investment securities held in trusts		(67,668	)		(87,193	)
Loans from (to) associated companies, net		(306,448	)		395
Other		(2,072	)		(593	)
Net cash used for investing activities		(361,566	)		(67,864	)
Net decrease in cash and cash equivalents		(19	)		(5	)
Cash and cash equivalents at beginning of period		144			135
Cash and cash equivalents at end of period	$	125		$	130
The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral
part of these statements.

 

87

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. Penelec has a partial requirements wholesale power sales agreement with FES, to supply a portion of each of its default service obligations at fixed prices through 2009. This sales agreement is renewed annually unless cancelled by either party with at least a sixty day written notice prior to the end of the calendar year.

Results of Operations

Net income decreased to $34 million in the first six months of 2009, compared to $40 million in the same period of 2008. The decrease was primarily due to lower revenues, partially offset by lower purchased power costs and decreased amortization of regulatory assets.

Revenues

Revenues decreased by $27 million, or 3.6%, in the first six months of 2009 primarily due to lower retail generation revenues and PJM transmission revenues, partially offset by higher wholesale generation revenues and distribution throughput revenues. Wholesale revenues increased $3 million in the first six months of 2009, compared to the same period of 2008, primarily reflecting higher KWH sales.

In the first six months of 2009, retail generation revenues decreased $19 million primarily due to lower KWH sales to the commercial and industrial customer classes due to weakened economic conditions, partially offset by a slight increase in KWH sales to the residential customer class.

Changes in retail generation sales and revenues in the first six months of 2009 compared to the same period of 2008 are summarized in the following tables:

Retail Generation KWH Sales	Increase (Decrease)
Residential		0.3	%
Commercial		(2.9	)%
Industrial		(16.9	)%
Net Decrease in Retail Generation Sales		(6.1	)%

Retail Generation Revenues	Decrease
	(In millions)
Residential	$	-
Commercial		(4	)
Industrial		(15	)
Decrease in Retail Generation Revenues	$	(19	)

Revenues from distribution throughput increased $5 million in the first six months of 2009 compared to the same period of 2008, primarily due to an increase in transmission rates, resulting from the annual update of Penelec's TSC rider effective June 1, 2008, and a slight increase in usage in the residential sector. Partially offsetting this increase was lower usage in the commercial and industrial sectors, reflecting economic conditions in Penelec’s service territory.

Changes in distribution KWH deliveries and revenues in the first six months of 2009 compared to the same period of 2008 are summarized in the following tables:

88

Distribution KWH Deliveries	Increase (Decrease)
Residential		0.3	%
Commercial		(2.9	)%
Industrial		(16.4	)%
Net Decrease in Distribution Deliveries		(6.3	)%

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

PJM transmission revenues decreased by $20 million in the first six months of 2009 compared to the same period of 2008, primarily due to lower revenues related to Penelec’s Financial Transmission Rights. Penelec defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.

Operating Expenses

Total operating expenses decreased by $7 million in the first six months of 2009 as compared with the same period of 2008. The following table presents changes from the prior year by expense category:

Expenses - Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	(6	)
Other operating costs		2
Provision for depreciation		4
Amortization of regulatory assets, net		(5	)
General taxes		(2	)
Net Decrease in Expenses	$	(7	)

Purchased power costs decreased by $6 million, or 1.5%, in the first six months of 2009 compared to the same period of 2008 due to reduced volume as a result of lower KWH sales requirements, partially offset by increased composite unit prices. Other operating costs increased by $2 million in the first six months of 2009 due primarily to higher pension and OPEB expenses. Depreciation expense increased primarily due to an increase in depreciable property since the second quarter of 2008. The net amortization of regulatory assets decreased in the first six months of 2009 primarily due to increased transmission cost deferrals as a result of increased net congestion costs.

Other Expense

In the first six months of 2009, other expense decreased primarily due to lower interest expense on borrowings from the regulated money pool combined with reduced interest expense on long-term debt due to the $100 million repayment of unsecured notes in April 2009.

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.

89

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, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2009 and 2008 and the consolidated statement of cash flows for the six-month periods ended June 30, 2009 and 2008. 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, 2008, 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 24, 2009, 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, 2008, 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 3, 2009

90

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30						June 30
	2009			2008			2009			2008
	(In thousands)
REVENUES:
Electric sales	$	316,881		$	335,382		$	688,174		$	711,410
Gross receipts tax collections		14,804			16,040			32,096			35,504
Total revenues		331,685			351,422			720,270			746,914
EXPENSES:
Purchased power from affiliates		72,166			62,568			168,247			146,032
Purchased power from non-affiliates		125,317			143,223			252,483			280,993
Other operating costs		46,301			50,100			123,590			121,177
Provision for depreciation		15,581			13,918			30,036			26,434
Amortization of regulatory assets, net		18,113			19,111			26,889			31,931
General taxes		18,251			18,345			38,844			40,200
Total expenses		295,729			307,265			640,089			646,767
OPERATING INCOME		35,956			44,157			80,181			100,147
OTHER INCOME (EXPENSE):
Miscellaneous income		911			1,058			1,709			867
Interest expense		(11,843	)		(14,901	)		(25,076	)		(30,223	)
Capitalized interest		29			70			51			(736	)
Total other expense		(10,903	)		(13,773	)		(23,316	)		(30,092	)
INCOME BEFORE INCOME TAXES		25,053			30,384			56,865			70,055
INCOME TAXES		10,232			11,987			23,354			30,266
NET INCOME		14,821			18,397			33,511			39,789
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		29,400			(3,474	)		32,355			(6,947	)
Unrealized gain on derivative hedges		16			16			32			32
Change in unrealized gain on available-for-sale securities		6			(21	)		(16	)		(10	)
Other comprehensive income (loss)		29,422			(3,479	)		32,371			(6,925	)
Income tax expense (benefit) related to other comprehensive income		15,100			(1,520	)		16,155			(3,026	)
Other comprehensive income (loss), net of tax		14,322			(1,959	)		16,216			(3,899	)
TOTAL COMPREHENSIVE INCOME	$	29,143		$	16,438		$	49,727		$	35,890
The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part
of these statements.

91

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,			December 31,
	2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	11		$	23
Receivables-
Customers (less accumulated provisions of $2,889,000 and $3,121,000,
respectively, for uncollectible accounts)		129,092			146,831
Associated companies		55,221			65,610
Other		11,976			26,766
Notes receivable from associated companies		14,770			14,833
Prepaid taxes		53,095			16,310
Other		482			1,517
		264,647			271,890
UTILITY PLANT:
In service		2,371,657			2,324,879
Less - Accumulated provision for depreciation		884,685			868,639
		1,486,972			1,456,240
Construction work in progress		28,105			25,146
		1,515,077			1,481,386
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		122,343			115,292
Non-utility generation trusts		118,302			116,687
Other		287			293
		240,932			232,272
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		768,628			768,628
Power purchase contract asset		21,347			119,748
Regulatory assets		9,911			-
Other		15,106			18,658
		814,992			907,034
	$	2,835,648		$	2,892,582
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	45,000		$	145,000
Short-term borrowings-
Associated companies		178,056			31,402
Other		250,000			250,000
Accounts payable-
Associated companies		27,055			63,692
Other		40,162			48,633
Accrued taxes		5,490			13,264
Accrued interest		11,462			13,131
Other		23,395			31,730
		580,620			596,852
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		912,420			912,441
Accumulated other comprehensive loss		(111,781	)		(127,997	)
Retained earnings		109,624			76,113
Total common stockholder's equity		998,815			949,109
Long-term debt and other long-term obligations		633,259			633,132
		1,632,074			1,582,241
NONCURRENT LIABILITIES:
Regulatory liabilities		-			136,579
Accumulated deferred income taxes		210,952			169,807
Retirement benefits		146,751			172,718
Asset retirement obligations		88,852			87,089
Power purchase contract liability		114,164			83,600
Other		62,235			63,696
		622,954			713,489
COMMITMENTS AND CONTINGENCIES (Note 8)
	$	2,835,648		$	2,892,582
The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company
are an integral part of these balance sheets.

92

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30
	2009			2008
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	33,511		$	39,789
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		30,036			26,434
Amortization of regulatory assets, net		26,889			31,931
Deferred costs recoverable as regulatory assets		(46,349	)		(13,288	)
Deferred income taxes and investment tax credits, net		24,700			12,760
Accrued compensation and retirement benefits		490			(16,293	)
Cash collateral		2			301
Decrease (increase) in operating assets-
Receivables		42,494			(11,082	)
Prepayments and other current assets		(35,750	)		(33,370	)
Increase (decrease) in operating liabilities-
Accounts payable		(10,108	)		(9,438	)
Accrued taxes		(7,629	)		(11,804	)
Accrued interest		(1,669	)		-
Other		2,302			9,714
Net cash provided from operating activities		58,919			25,654
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			45,000
Short-term borrowings, net		146,654			96,880
Redemptions and Repayments-
Long-term debt		(100,000	)		(45,320	)
Dividend Payments-
Common stock		(35,000	)		(55,000	)
Net cash provided from financing activities		11,654			41,560
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(59,606	)		(57,314	)
Loan repayments from (loans to) associated companies, net		63			(151	)
Sales of investment securities held in trust		53,504			45,108
Purchases of investment securities held in trust		(60,378	)		(53,537	)
Other		(4,168	)		(1,328	)
Net cash used for investing activities		(70,585	)		(67,222	)
Net decrease in cash and cash equivalents		(12	)		(8	)
Cash and cash equivalents at beginning of period		23			46
Cash and cash equivalents at end of period	$	11		$	38
The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an
integral part of these statements.

93

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 Utilities. This information should be read in conjunction with (i) FES' and the Utilities' 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 Utilities; and (iii) FES' and the Utilities' respective 2008 Annual Reports on Form 10-K.

Regulatory Matters(Applicable to each of the Utilities)

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

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

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

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

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

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

· requiring corporate separation of regulated and unregulated business activities.

The Utilities 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 $158 million as of June 30, 2009 (JCP&L - $48 million, Met-Ed - $95 million and Penelec - $15 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 and Penelec. The following table discloses net regulatory assets by company:

	June 30,		December 31,		Increase
Regulatory Assets	2009		2008		(Decrease)
	(In millions)
OE	$	514	$	575	$	(61	)
CEI		628		784		(156	)
TE		91		109		(18	)
JCP&L		1,055		1,228		(173	)
Met-Ed		497		413		84
Penelec*		10		-		10
ATSI		24		31		(7	)
Total	$	2,819	$	3,140	$	(321	)

* Penelec had net regulatory liabilities of approximately $137 million as of December 31, 2008. These net regulatory liabilities are included in Other Non-current Liabilities on the Consolidated Balance Sheets.

94

Ohio (Applicable to OE, CEI, TE and FES)

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. On January 21, 2009, the PUCO granted the Ohio Companies’ application to increase electric distribution rates by $136.6 million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million). These increases went into effect for OE and TE on January 23, 2009, and for CEI on May 1, 2009. Applications for rehearing of this order were filed by the Ohio Companies and one other party on February 20, 2009. The PUCO granted these applications for rehearing on March 18, 2009 for the purpose of further consideration. The PUCO has not yet issued a substantive Entry on Rehearing.

SB221, which became effective on July 31, 2008, required all electric utilities to file an ESP, and permitted the filing of an MRO. On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and a separate MRO. The PUCO denied the MRO application; however, the PUCO later granted the Ohio Companies’ application for rehearing for the purpose of further consideration of the matter, which is still pending. The ESP proposed to phase in new generation rates for customers beginning in 2009 for up to a three-year period and resolve the Ohio Companies’ collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. In response to the PUCO’s December 19, 2008 order, which significantly modified and approved the ESP as modified, the Ohio Companies notified the PUCO that they were withdrawing and terminating the ESP application in addition to continuing their current rate plan in effect as allowed by the terms of SB221. On December 31, 2008, the Ohio Companies conducted a CBP for the procurement of electric generation for retail customers from January 5, 2009 through March 31, 2009. The average winning bid price was equivalent to a retail rate of 6.98 cents per KWH. The power supply obtained through this process provided generation service to the Ohio Companies’ retail customers who chose not to shop with alternative suppliers. On January 9, 2009, the Ohio Companies requested the implementation of a new fuel rider to recover the costs resulting from the December 31, 2008 CBP. The PUCO ultimately approved the Ohio Companies’ request for a new fuel rider to recover increased costs resulting from the CBP but denied OE’s and TE’s request to continue collecting RTC and denied the request to allow the Ohio Companies to continue collections pursuant to the two existing fuel riders. The new fuel rider recovered the increased purchased power costs for OE and TE, and recovered a portion of those costs for CEI, with the remainder being deferred for future recovery.

On January 29, 2009, the PUCO ordered its Staff to develop a proposal to establish an ESP for the Ohio Companies. On February 19, 2009, the Ohio Companies filed an Amended ESP application, including an attached Stipulation and Recommendation that was signed by the Ohio Companies, the Staff of the PUCO, and many of the intervening parties. Specifically, the Amended ESP provided that generation would be provided by FES at the average wholesale rate of the CBP process described above for April and May 2009 to the Ohio Companies for their non-shopping customers; for the period of June 1, 2009 through May 31, 2011, retail generation prices would be based upon the outcome of a descending clock CBP on a slice-of-system basis. The Amended ESP further provided that the Ohio Companies will not seek a base distribution rate increase, subject to certain exceptions, with an effective date of such increase before January 1, 2012, that CEI would agree to write-off approximately $216 million of its Extended RTC balance, and that the Ohio Companies would collect a delivery service improvement rider at an overall average rate of $.002 per KWH for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addressed a number of other issues, including but not limited to, rate design for various customer classes, and resolution of the prudence review and the collection of deferred costs that were approved in prior proceedings. On February 26, 2009, the Ohio Companies filed a Supplemental Stipulation, which was signed or not opposed by virtually all of the parties to the proceeding, that supplemented and modified certain provisions of the February 19, 2009 Stipulation and Recommendation. Specifically, the Supplemental Stipulation modified the provision relating to governmental aggregation and the Generation Service Uncollectible Rider, provided further detail on the allocation of the economic development funding contained in the Stipulation and Recommendation, and proposed additional provisions related to the collaborative process for the development of energy efficiency programs, among other provisions. The PUCO adopted and approved certain aspects of the Stipulation and Recommendation on March 4, 2009, and adopted and approved the remainder of the Stipulation and Recommendation and Supplemental Stipulation without modification on March 25, 2009. Certain aspects of the Stipulation and Recommendation and Supplemental Stipulation took effect on April 1, 2009 while the remaining provisions took effect on June 1, 2009.

On July 27, 2009, the Ohio Companies filed applications with the PUCO to recover three different categories of deferred distribution costs on an accelerated basis. In the Ohio Companies' Amended ESP, the PUCO approved the recovery of these deferrals, with collection originally set to begin in January 2011 and to continue over a 5 or 25 year period. The principal amount plus carrying charges through August 31, 2009 for these deferrals is a total of $298.4 million. If the applications are approved, recovery of this amount, together with carrying charges calculated as approved in the Amended ESP, will be collected in the 18 non-summer months from September 2009 through May 2011, subject to reconciliation until fully collected, with $165 million of the above amount being recovered from residential customers, and $133.4 million being recovered from non-residential customers. Pursuant to the applications, customers would pay significantly less over the life of the recovery of the deferral through the reduction in carrying charges as compared to the expected recovery under the previously approved recovery mechanism.

95

The Ohio Companies are presently involved in collaborative efforts related to energy efficiency and a competitive bidding process, together with other implementation efforts arising out of the Supplemental Stipulation. The CBP auction occurred on May 13-14, 2009, and resulted in a weighted average wholesale price for generation and transmission of 6.15 cents per KWH. The bid was for a single, two-year product for the service period from June 1, 2009 through May 31, 2011. FES participated in the auction, winning 51% of the tranches (one tranche equals one percent of the load supply). Subsequent to the signing of the wholesale contracts, two winning bidders reached separate agreements with FES to assign a total of 11 tranches to FES for various periods. In addition, FES has separately contracted with numerous communities to provide retail generation service through governmental aggregation programs.

As a result of the CBP auction, FES expects to sell less of its generation output to its affiliated utilities in 2009 and 2010 than it has done historically. By 2011, FES' supply obligations to its affiliated Pennsylvania utilities expire pursuant to the terms of the existing partial requirements wholesale power agreement, with all of its output expected to be subject to market-based generation pricing. Accordingly, FES continues to focus on expanding its retail opportunities and has recently increased retail sales to governmental aggregation groups in Ohio and large industrial customers both inside and outside of Ohio. As of August 1, 2009, FES has signed 50 government aggregation contracts that will provide discounted generation prices to approximately 600,000 residential and small commercial customers. The governmental aggregator may choose between a graduated or flat percentage discount. When FES' sales to the governmental aggregation groups are combined with all of its other committed sales, including its position in the Ohio auction, FES' total generation hedged as a percentage of forecasted output is expected to be 93% in 2009 and 76% in 2010.

SB221 also requires electric distribution utilities to implement energy efficiency programs that achieve a total annual energy savings equivalent of approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013. Utilities are also required to reduce peak demand in 2009 by 1%, with an additional seventy-five hundredths of one percent reduction each year thereafter through 2018. Additionally, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they serve in 2009. FirstEnergy has efforts underway to address compliance with these requirements. Costs associated with compliance are recoverable from customers.

On June 17, 2009, the PUCO modified rules that implement the alternative energy portfolio standards created by SB221, including the incorporation of energy efficiency requirements, long-term forecast and greenhouse gas reporting and CO2 control planning. The PUCO filed the rules with the Joint Committee on Agency Rule Review on July 7, 2009, after which begins a 65-day review period. The Ohio Companies and one other party filed applications for rehearing on the rules with the PUCO on July 17, 2009.

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. 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. 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. See FERC Matters below for a description of the Third Restated Partial Requirements Agreement, executed by the parties on October 31, 2008, that limits the amount of energy and capacity FES must supply to Met-Ed and Penelec. In the event of a third party supplier default, the increased costs to Met-Ed and Penelec could be material.

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 those filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing Met-Ed 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. Hearings and briefing for both Met-Ed and Penelec have concluded and the companies are awaiting a Recommended Decision from the ALJ. The TSCs included a component from under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for 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.

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On May 28, 2009, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the period June 1, 2009 through May 31, 2010, as required in connection with the PPUC’s January 2007 rate order. For Penelec’s customers the new TSC resulted in an approximate 1% decrease in monthly bills, reflecting projected PJM transmission costs as well as a reconciliation for costs already incurred. The TSC for Met-Ed’s customers increased to recover the additional PJM charges paid by Met-Ed in the previous year and to reflect updated projected costs. In order to gradually transition customers to the higher rate, the PPUC approved Met-Ed’s proposal to continue to recover the prior period deferrals allowed in the PPUC’s May 2008 Order and defer $57.5 million of projected costs to a future TSC to be fully recovered by December 31, 2010. Under this proposal, monthly bills for Met-Ed’s customers will increase approximately 9.4% for the period June 2009 through May 2010.

On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law which became effective on November 14, 2008 as Act 129 of 2008. Act 129 addresses issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Major provisions of the legislation include:

·   power acquired by utilities to serve customers after rate caps expire will be procured through a competitive procurement process that must include a prudent mix of long-term and short-term contracts and spot market purchases;

·   the competitive procurement process must be approved by the PPUC and may include auctions, RFPs, and/or bilateral agreements;

·   utilities must provide for the installation of smart meter technology within 15 years;

·   utilities must reduce peak demand by  a minimum of 4.5% by May 31, 2013;

·   utilities must reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively; and

·   the definition of Alternative Energy was expanded to include additional types of hydroelectric and biomass facilities.

Act 129 requires utilities to file with the PPUC an energy efficiency and peak load reduction plan by July 1, 2009, and a smart meter procurement and installation plan by August 14, 2009. On January 15, 2009, in compliance with Act 129, the PPUC issued its proposed guidelines for the filing of utilities’ energy efficiency and peak load reduction plans. On June 18, 2009, the PPUC issued its guidelines related to Smart Meter deployment. On July 1, 2009, Met-Ed, Penelec, and Penn filed Energy Efficiency and Conservation Plans with the PPUC in accordance with Act 129.

Legislation addressing rate mitigation and the expiration of rate caps was not enacted in 2008; however, several bills addressing these issues have been introduced in the current legislative session, which began in January 2009. The final form and impact of such legislation is uncertain.

On February 20, 2009, Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The companies’ plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposes a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. Met-Ed and Penelec have requested PPUC approval of their plan by November 2009.

On February 26, 2009, the PPUC approved a Voluntary Prepayment Plan requested by Met-Ed and Penelec that provides an opportunity for residential and small commercial customers to prepay an amount on their monthly electric bills during 2009 and 2010. Customer prepayments earn interest at 7.5% and will be used to reduce electricity charges in 2011 and 2012.

On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance filing to the PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the residential class with a corresponding increase in the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $51 million), overall rates would remain unchanged. On July 30, 2009, the PPUC entered an order approving the 5-year NUG Statement, approving the reduction of the CTC, and directing Met-Ed and Penelec to file a tariff supplement implementing this change. On July 31, 2009, Met-Ed and Penelec filed tariff supplements decreasing the CTC rate in compliance with the July 30, 2009 order, and increasing the generation rate in compliance with the companies’ Restructuring Orders of 1998. Met-Ed and Penelec are awaiting PPUC action on the July 31, 2009 filings.

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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, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of June 30, 2009, the accumulated deferred cost balance totaled approximately $149 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 DPA 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 March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009. This matter is currently pending before the NJBPU.

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.

The EMP was issued on October 22, 2008, establishing 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 30% of the state’s electricity needs with renewable energy by 2020;

·   examine smart grid technology and develop additional cogeneration and other generation resources consistent with the state’s greenhouse gas targets; and

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

On January 28, 2009, the NJBPU adopted an order establishing the general process and contents of specific EMP plans that must be filed by December 31, 2009 by New Jersey electric and gas utilities in order to achieve the goals of the EMP. At this time, JCP&L cannot determine the impact, if any, the EMP may have on its operations.

In support of the New Jersey Governor's Economic Assistance and Recovery Plan, JCP&L announced a proposal to spend approximately $98 million on infrastructure and energy efficiency projects in 2009.  Under the proposal, an estimated $40 million would be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations.  Approximately $34 million would be spent implementing new demand response programs as well as expanding on existing programs.  Another $11 million would be spent on energy efficiency, specifically replacing transformers and capacitor control systems and installing new LED street lights. The remaining $13 million would be spent on energy efficiency programs that would complement those currently being offered. Implementation of the projects is dependent upon resolution of regulatory issues including recovery of the costs associated with the proposal.

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

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 is pending before the FERC, and 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. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements.

PJM Transmission Rate

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. AEP's 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. 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. Oral arguments were held on April 13, 2009. A decision is expected this summer.

The FERC’s orders on PJM rate design would 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 would 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 to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement subject to the submission of a compliance filing. The compliance filing was submitted on August 29, 2008, and the FERC issued an order accepting the compliance filing on October 15, 2008. On November 14, 2008, PJM submitted revisions to its tariff to incorporate cost responsibility assignments for below 500 kV upgrades included in PJM’s Regional Transmission Expansion Planning process in accordance with the settlement. The FERC conditionally accepted the compliance filing on January 28, 2009. PJM submitted a further compliance filing on March 2, 2009, which was accepted by the FERC on April 10, 2009. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. An initial decision was issued by the Presiding Judge on September 18, 2008. PJM and FERC trial staff each filed a Brief on Exceptions to the initial decision on October 20, 2008. Briefs Opposing Exceptions were filed on November 10, 2008.

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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 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. The effect of this order is to prevent the shift of significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP was denied by the FERC on December 19, 2008. On February 17, 2009, AEP appealed the FERC’s January 31, 2008, and December 19, 2008, orders to the U.S. Court of Appeals for the Seventh Circuit. FESC, on behalf of its affiliated operating utility companies, filed a motion to intervene on March 10, 2009.

Changes ordered for PJM Reliability Pricing Model (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. On September 19, 2008, the FERC denied the RPM Buyers’ complaint. The FERC also ordered PJM to file on or before December 15, 2008, a report on potential adjustments to the RPM program as suggested in a Brattle Group report. On December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the RPM program. PJM also requested that the FERC conduct a settlement hearing to address changes to the RPM and suggested that the FERC should rule on the tariff amendments only if settlement could not be reached in January, 2009. The request for settlement hearings was granted. Settlement had not been reached by January 9, 2009 and, accordingly, FirstEnergy and other parties submitted comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief Judge issued an order terminating settlement discussions. On February 9, 2009, PJM and a group of stakeholders submitted an offer of settlement, which used the PJM December 12, 2008 filing as its starting point, and stated that unless otherwise specified, provisions filed by PJM on December 12, 2008, apply.

On March 26, 2009, the FERC accepted in part, and rejected in part, tariff provisions submitted by PJM, revising certain parts of its RPM. Ordered changes included making incremental improvements to RPM; however, the basic construct of RPM remains intact. On April 3, 2009, PJM filed with the FERC requesting clarification on certain aspects of the March 26, 2009 Order. On April 27, 2009, PJM submitted a compliance filing addressing the changes the FERC ordered in the March 26, 2009 Order; and subsequently, numerous parties filed requests for rehearing of the March 26, 2009 Order. On June 18, 2009, the FERC denied rehearing and request for oral argument of the March 26 Order.

PJM has reconvened the Capacity Market Evolution Committee to address issues not addressed in the February 2009 settlement in preparation for September 1, 2009 and December 1, 2009 compliance filings that will recommend more incremental improvements to its RPM.

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 and FES. This requirement was 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 submitted 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.

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On October 20, 2008, the FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a compliance filing modifying the cost of new entry penalty. Second, the FERC conditionally accepted MISO's compliance filing on the qualifications for purchased power agreements to be capacity resources, load forecasting, loss of load expectation, and planning reserve zones. Additional compliance filings were directed on accreditation of load modifying resources and price responsive demand. Finally, the FERC largely denied rehearing of its March 26 order with the exception of issues related to behind the meter resources and certain ministerial matters. On November 19, 2008, MISO made various compliance filings pursuant to these orders. Issuance of orders on rehearing and two of the compliance filings occurred on February 19, 2009. No material changes were made to MISO’s Resource Adequacy program. On April 16, 2009, the FERC issued an additional order on rehearing and compliance, approving MISO’s proposed financial settlement provision for Resource Adequacy. The MISO Resource Adequacy process was implemented as planned on June 1, 2009, the beginning of the MISO planning year. On June 17, 2009, MISO submitted a compliance filing in response to the FERC’s April 16, 2009 order directing it to address, among others, various market monitoring and mitigation issues. On July 8, 2009, various parties submitted comments on and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific aspects of the MISO’s and Independent Market Monitor’s proposals for market monitoring and mitigation and other issues that it believes the FERC should address and clarify.

FES Sales to Affiliates

FES supplied all of the power requirements for the Ohio Companies pursuant to a Power Supply Agreement that ended on December 31, 2008. On January 2, 2009, FES signed an agreement to provide 75% of the Ohio Companies’ power requirements for the period January 5, 2009 through March 31, 2009. Subsequently, FES signed an agreement to provide 100% of the Ohio Companies’ power requirements for the period April 1, 2009 through May 31, 2009. On March 4, 2009, the PUCO issued an order approving these two affiliate sales agreements. FERC authorization for these affiliate sales was by means of a December 23, 2008 waiver of restrictions on affiliate sales without prior approval of the FERC.

On May 13-14, 2009, the Ohio Companies held an auction to secure generation supply for their PLR obligation. The results of the auction were accepted by the PUCO on May 14, 2009. Twelve bidders qualified to participate in the auction with nine successful bidders each securing a portion of the Ohio Companies' total supply needs. FES was the successful bidder for 51 tranches, and subsequently purchased 11 additional tranches from other bidders. The auction resulted in an overall weighted average wholesale price of 6.15 cents per KWH for generation and transmission. The new prices for PLR service went into effect with usage beginning June 1, 2009, and continuing through May 31, 2011.

On October 31, 2008, FES executed a Third Restated Partial Requirements Agreement with Met-Ed, Penelec, and Waverly effective November 1, 2008. The Third Restated Partial Requirements Agreement limits the amount of capacity and energy required to be supplied by FES in 2009 and 2010 to approximately two-thirds of those affiliates’ power supply requirements. Met-Ed, Penelec, and Waverly have committed resources in place for the balance of their expected power supply during 2009 and 2010. Under the Third Restated Partial Requirements Agreement, Met-Ed, Penelec, and Waverly are responsible for obtaining additional power supply requirements created by the default or failure of supply of their committed resources. Prices for the power provided by FES were not changed in the Third Restated Partial Requirements Agreement.

Environmental Matters

Various federal, state and local authorities regulate FES and the Utilities with regard to air and water quality and other environmental matters. The effects of compliance on FES and the Utilities 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 and the Utilities 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 Utilities' 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, OE, JCP&L, Met-Ed and Penelec)

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 $37,500 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.

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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. 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, the generation of more electricity at lower-emitting plants, and/or using emission allowances. 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.

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 and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s 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 was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices or repowering and provides for stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree, including repowering Burger Units 4 and 5 for biomass fuel consumption, are currently estimated to be $706 million for 2009-2012 (with $414 million expected to be spent in 2009).

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. In July 2008, three additional complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania 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. On October 14, 2008, the Court granted FGCO’s motion to consolidate discovery for all four complaints pending against the Bruce Mansfield Plant. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints. The Pennsylvania Department of Health, under a Cooperative Agreement with the Agency for Toxic Substances and Disease Registry, completed a Health Consultation regarding the Mansfield Plant and issued a report dated March 31, 2009 which concluded there is insufficient sampling data to determine if any public health threat exists for area residents due to emissions from the Mansfield Plant. The report recommended additional air monitoring and sample analysis in the vicinity of the Mansfield Plant which the Pennsylvania Department of Environmental Protection is currently conducting.

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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.  On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. Specifically, Connecticut and New Jersey allege that "modifications" at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed.  On December 5, 2008, New Jersey filed an amended complaint, adding claims with respect to alleged modifications that occurred after GPU’s sale of the plant. Met-Ed filed a Motion to Dismiss the claims in New Jersey’s Amended Complaint and Connecticut’s Complaint on February 19, 2009. On January 14, 2009, the EPA issued a NOV to Reliant alleging new source review violations at the Portland Generation Station based on “modifications” dating back to 1986. Met-Ed is unable to predict the outcome of this matter. The EPA’s January 14, 2009, NOV also alleged new source review violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of Keystone Station and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter. On June 1, 2009, the Court held oral argument on Met-Ed’s motion to dismiss the complaint.

On June 11, 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. 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. Mission Energy is seeking indemnification from Penelec, 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. The scope of Penelec’s indemnity obligation to and from Mission Energy 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 Administrative Consent Order modifying that request and setting forth a schedule for FGCO’s response. On October 27, 2008, FGCO received a second request from the EPA for information pursuant to Section 114(a) of the CAA for additional operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants. FGCO intends to fully comply with the EPA’s information requests, but, at this time, is unable to predict the outcome of this matter.

On August 18, 2008, FirstEnergy received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding its formerly-owned Avon Lake and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. FirstEnergy intends to fully comply with the EPA’s information request, 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 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 requires 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 2.5 million tons annually and NOX emissions to 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.” On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. On December 23, 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s July 11, 2008 opinion. On July 10, 2009, the United States Court of Appeals for the District of Columbia ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOX SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the "8-hour" ozone NAAQS. FGCO's future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA in response to the Court’s ruling.

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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. On October 17, 2008, the EPA (and an industry group) petitioned the United States Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the EPA moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the EPA’s petition and denied the industry group’s petition. The EPA is developing 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 any future regulations 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. On January 30, 2009, the Commonwealth Court of Pennsylvania declared Pennsylvania’s mercury rule “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule. It is anticipated that compliance with these regulations, if the Commonwealth Court’s rulings were reversed on appeal and Pennsylvania’s mercury rule was 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.

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, by 2012, the amount of man-made GHG, including CO2, emitted by developed countries. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. 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. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity used in the United States comes from renewable sources by 2012, increasing to 25% by 2025, and implementing an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050.

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 House of Representatives passed one such bill, the American Clean Energy and Security Act of 2009, on June 26, 2009. 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 April 17, 2009, the EPA released a “Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s proposed finding concludes that the atmospheric concentrations of several key greenhouse gases threaten the health and welfare of future generations and that the combined emissions of these gases by motor vehicles contribute to the atmospheric concentrations of these key greenhouse gases and hence to the threat of climate change. Although the EPA’s proposed finding, if finalized, does not establish emission requirements for motor vehicles, such requirements would be expected to occur through further rulemakings. Additionally, while the EPA’s proposed findings do not specifically address stationary sources, including electric generating plants, those findings, if finalized, would be expected to support the establishment of future emission requirements by the EPA for stationary sources.

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.

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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.

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 1, 2009, the Supreme Court of the United States reversed one significant aspect of the Second Circuit Court’s opinion and decided that 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 and 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.

The U.S. Attorney's Office in Cleveland, Ohio has advised FGCO that it is considering prosecution under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007. FGCO is unable to predict the outcome of this matter.

Regulation of Waste Disposal (Applicable to FES and each of the Utilities)

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. In February 2009, the EPA requested comments from the states on options for regulating coal combustion wastes, including regulation as non-hazardous waste or regulation as a hazardous waste. In March and June 2009, the EPA requested information from FGCO’s Bruce Mansfield Plant regarding the management of coal combustion wastes. FGCO's future cost of compliance with any coal combustion waste regulations which may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the states.

The Utilities have been named as potentially responsible parties 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 potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the consolidated balance sheet as of June 30, 2009, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $104 million (JCP&L - - $77 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through June 30, 2009. Included in the total are accrued liabilities of approximately $68 million for environmental remediation of former manufactured gas plants and gas holder facilities 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.  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 due to the outages.

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After various motions, rulings and appeals, the Plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability, and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. The class was decertified twice by the trial court, and appealed both times by the Plaintiffs, with the results being that: (1) the Appellate Division limited the class only 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 which resulted in planned and unplanned outages in the area during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. On March 31, 2009, the trial court again granted JCP&L’s motion to decertify the class. On April 20, 2009, the Plaintiffs filed a motion for leave to take an interlocutory appeal to the trial court's decision to decertify the class, which was granted by the Appellate Division on June 15, 2009. According to the scheduling order issued by the Appellate Division, Plaintiffs' opening brief is due on August 25, 2009, JCP&L's opposition brief is due on September 25, 2009, and Plaintiffs' reply is due on October 5, 2009.

Nuclear Plant Matters (Applicable to FES)

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. On June 8, 2009, the NRC issued the final Safety Evaluation Report (SER) supporting the renewed license for Beaver Valley Units 1 and 2. On July 8, 2009, the NRC’s Advisory Committee on Reactor Safeguards (ACRS) held a public meeting to consider the NRC’s final SER. Much of the ACRS’ discussion involved questions raised by a letter from Citizens Power regarding the extent of corrective actions for the 2009 discovery of a penetration in the Beaver Valley Unit 1 containment liner. On July 28, 2009, FENOC submitted to the NRC further clarifications on the supplemental volumetric examinations of Beaver Valley’s containment liners. FENOC anticipates another meeting with the ACRS regarding the container liner during September 2009. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and is scheduled 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.

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of June 30, 2009, FirstEnergy had approximately $1.7 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 provided an additional $80 million parental guarantee associated with the funding of decommissioning costs for these units and indicated that it planned to contribute an additional $80 million to these trusts by 2010.  As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s obligations to fund the trusts may increase. The recent disruption in the capital markets and its effects on particular businesses and the economy in general also affects the values of the nuclear decommission trusts. On June 18, 2009, the NRC informed FENOC that its review tentatively concluded that a shortfall ($147.5 million net present value) existed in the value of the decommissioning trust fund for Beaver Valley Unit 1. On July 28, 2009, FENOC submitted a letter to the NRC that stated reasonable assurance of decommissioning funding is provided for Beaver Valley Unit 1 through a combination of the existing trust fund balances, the existing $80 million parental guarantee from FirstEnergy and maintaining the plant in a safe-store configuration, or extended safe shutdown condition, after plant shutdown. Renewal of the operating license for Beaver Valley Unit 1, as described above, would mitigate the estimated shortfall in the unit’s nuclear decommissioning funding status. FENOC continues to communicate with the NRC regarding future actions to provide reasonable assurance for decommissioning funding. Such actions may include additional parental guarantees or contributions to those funds.

Other Legal Matters  (Applicable to FES and each of the Utilities)

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

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. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. A final order identifying the individual damage amounts was issued on October 31, 2007 and 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 and oral arguments were held in the fall. On February 25, 2009, the federal district court denied JCP&L’s motion to vacate the arbitration decision and granted the union’s motion to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009. The appeal process could take as long as 24 months. JCP&L recognized a liability for the potential $16 million award in 2005. Post-judgment interest began to accrue as of February 25, 2009, and the liability will be adjusted accordingly.

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The bargaining unit employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. On July 24, 2009, FirstEnergy declared that bargaining was at an impasse and portions of its last contract offer were implemented August 1, 2009.  A federal mediator is continuing to assist the parties in reaching a negotiated contract settlement. FirstEnergy has a strike mitigation plan ready in the event of a strike.

On May 21, 2009, 517 Penelec employees, represented by the International Brotherhood of Electrical Workers (IBEW) Local 459, elected to strike. In response, on May 22, 2009, Penelec implemented its work-continuation plan to use nearly 400 non-represented employees with previous line experience and training drawn from Penelec and other FirstEnergy operations to perform service reliability and priority maintenance work in Penelec’s service territory. Penelec's IBEW Local 459 employees ratified a three-year contract agreement on July 19, 2009, and returned to work on July 20, 2009.

On June 26, 2009, FirstEnergy announced that seven of its union locals, representing about 2,600 employees, have ratified contract extensions. These unions include employees from Penelec, Penn, CEI, OE and TE, along with certain power plant employees.

On July 8, 2009, FirstEnergy announced that employees of Met-Ed represented by IBEW Local 777 ratified a two-year contract. Union members had been working without a contract since the previous agreement expired on April 30, 2009.

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

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

FSP FAS 132 (R)-1 – “Employers’ Disclosures about Postretirement Benefit Plan Assets”

In December 2008, the FASB issued Staff Position FAS 132(R)-1, which provides guidance on an employer’s disclosures about assets of a defined benefit pension or other postretirement plan. Requirements of this FSP include disclosures about investment policies and strategies, categories of plan assets, fair value measurements of plan assets, and significant categories of risk. This FSP is effective for fiscal years ending after December 15, 2009. FES and the Utilities will expand their disclosures related to postretirement benefit plan assets as a result of this FSP.

SFAS 166 – “Accounting for Transfers of Financial Assets – an amendment of FASB Statement No. 140”

In June 2009, the FASB issued SFAS 166, which amends the derecognition guidance in SFAS 140 and eliminates the concept of a qualifying special-purpose entity (QSPE). It removes the exception from applying FIN 46R to QSPEs and requires an evaluation of all existing QSPEs to determine whether they must be consolidated in accordance with SFAS 167. This Statement is effective for financial asset transfers that occur in fiscal years beginning after November 15, 2009. FES and the Utilities do not expect this Standard to have a material effect upon their financial statements.

SFAS 167 – “Amendments to FASB Interpretation No. 46(R)”

In June 2009, the FASB issued SFAS 167, which amends the consolidation guidance applied to VIEs. This Statement replaces the quantitative approach previously required to determine which entity has a controlling financial interest in a VIE with a qualitative approach. Under the new approach, the primary beneficiary of a VIE is the entity that has both (a) the power to direct the activities of the VIE that most significantly impact the entity’s economic performance, and (b) the obligation to absorb losses of the entity, or the right to receive benefits from the entity, that could be significant to the VIE. SFAS 167 also requires ongoing reassessments of whether an entity is the primary beneficiary of a VIE and enhanced disclosures about an entity’s involvement in VIEs. This Statement is effective for fiscal years beginning after November 15, 2009. FES and the Utilities are currently evaluating the impact of adopting this Standard on their financial statements.

SFAS 168 – “The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162”

In June 2009, the FASB issued SFAS 168, which recognizes the FASB Accounting Standards CodificationTM (Codification) as the source of authoritative GAAP. It also recognizes that rules and interpretative releases of the SEC under federal securities laws are sources of authoritative GAAP for SEC registrants. The Codification supersedes all non-SEC accounting and reporting standards. This Statement is effective for financial statements issued for interim and annual periods ending after September 15, 2009. This Statement will change how FES and the Utilities reference GAAP in their financial statement disclosures.

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Debt Capacity and Financing Activities(Applicable to FES and each of the Utilities)

Long-Term Debt Capacity

As of June 30, 2009, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.3 billion of additional FMBs on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMBs by the Ohio Companies 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 FMBs) supporting pollution control notes or similar obligations, or as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE and CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $167 million and $175 million, respectively, as of June 30, 2009. In April 2009, TE issued $300 million of new senior secured notes backed by FMBs. Concurrently with that issuance, and in order to satisfy the limitation on secured debt under its senior note indenture, TE issued an additional $300 million of FMBs to secure $300 million of its outstanding unsecured senior notes originally issued in November 2006. As a result, the provisions for TE to incur additional secured debt do not apply.

Based upon FGCO's FMB indenture, net earnings and available bondable property additions as of June 30, 2009, FGCO had the capability to issue $2.2 billion of additional FMBs under the terms of that indenture. On June 16, 2009, FGCO issued a total of approximately $395.9 million in principal amount of FMBs, of which $247.7 million related to three new refunding series of PCRBs and approximately $148.2 million related to amendments to existing letter of credit and reimbursement agreements supporting two other series of PCRBs. On June 30, 2009, FGCO issued a total of approximately $52.1 million in principal amount of FMBs related to three existing series of PCRBs.

In June 2009, a new FMB indenture was put in place for NGC. Based upon NGC’s FMB indenture, net earnings and available bondable property additions, NGC had the capability to issue $264 million of additional FMBs as of June 30, 2009. On June 16, 2009, NGC issued a total of approximately $487.5 million in principal amount of FMBs, of which $107.5 million related to one new refunding series of PCRBs and approximately $380 million related to amendments to existing letter of credit and reimbursement agreements supporting seven other series of PCRBs. In addition, on June 16, 2009, NGC issued an FMB in a principal amount of up to $500 million in connection with its guaranty of FES’ obligations to post and maintain collateral under the Power Supply Agreement entered into by FES with the Ohio Companies as a result of the May 13-14, 2009 CBP auction. On June 30, 2009, NGC issued a total of approximately $273.3 million in principal amount of FMBs, of which approximately $92 million related to three existing series of PCRBs and approximately $181.3 million related to amendments to existing letter of credit and reimbursement agreements supporting three other series of PCRBs.

Met-Ed and Penelec had the capability to issue secured debt of approximately $428 million and $310 million, respectively, under provisions of their senior note indentures as of June 30, 2009.

FES' and the Utilities’ access to capital markets and costs of financing are influenced by the ratings of their securities and those of FirstEnergy. The following table displays FirstEnergy's, FES' and the Utilities' securities ratings as of June 30, 2009. On June 17, 2009, Moody's affirmed FirstEnergy’s Baa3 and FES' Baa2 credit ratings. On July 9, 2009, S&P affirmed its ratings on FirstEnergy and its subsidiaries. S&P's and Moody's outlook for FirstEnergy and its subsidiaries remains "stable."

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

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On September 22, 2008, FirstEnergy, along with the Shelf Registrants, filed an automatically effective shelf registration statement with the SEC for an unspecified number and amount of securities to be offered thereon. The shelf registration provides FirstEnergy the flexibility to issue and sell various types of securities, including common stock, preferred stock, debt securities, warrants, share purchase contracts, and share purchase units. The Shelf Registrants have utilized, and may in the future utilize, the shelf registration statement to offer and sell unsecured and, in some cases, secured debt securities. On July 29, 2009, FES registered its common stock pursuant to Section 12(g) of the Securities Exchange Act of 1934.

Pollution Control Revenue Bonds

As of June 30, 2009, FES’, Met-Ed’s and Penelec’s currently payable long-term debt included $1.5 billion, $29 million and $45 million, respectively, of variable interest rate PCRBs, the bondholders of which are entitled to the benefit of irrevocable direct pay bank LOCs. The interest rates on the PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory purchase prior to maturity with the purchase price payable from remarketing proceeds or, if the PCRBs are not successfully remarketed, by drawings on the irrevocable direct pay LOCs. The subsidiary obligor is required to reimburse the applicable LOC bank for any such drawings or, if the LOC bank fails to honor its LOC for any reason, must itself pay the purchase price.

In February 2009, holders of approximately $434 million principal of LOC-supported PCRBs of OE and NGC were notified that the applicable Wachovia Bank LOCs were to expire on March 18, 2009. As a result, these PCRBs were subject to mandatory purchase at a price equal to the principal amount, plus accrued and unpaid interest, which OE and NGC funded through short-term borrowings. In March 2009, FGCO remarketed $100 million of those PCRBs, which were previously held by OE. During the second quarter of 2009, NGC remarketed the remaining $334 million of PCRBs, of which $170 million was remarketed in fixed interest rate modes and secured by FMBs, thereby eliminating the need for third-party credit support. During the second quarter of 2009, FGCO remarketed approximately $248 million of PCRBs supported by LOCs set to expire in June 2009. These PCRBs were remarketed in fixed interest rate modes and secured by FMBs, thereby eliminating the need for third-party credit support. Also, in June 2009, FGCO and NGC delivered FMBs to certain LOC banks listed above in connection with amendments to existing letter of credit and reimbursement agreements supporting 12 other series of PCRBs as described above and pledged FMBs to the applicable trustee under six separate series of PCRBs.

Financing Activities

The following table summarizes new debt issuances (excluding PCRB issuances and refinancings) during 2009.

Issuing Company	Issue Date	Principal (in millions)	Type	Maturity	Use of Proceeds
Met-Ed*	01/20/2009	$300	7.70% Senior Notes	2019	Repay short-term borrowings
JCP&L*	01/27/2009	$300	7.35% Senior Notes	2019	Repay short-term borrowings, fund capital expenditures and other general purposes
TE*	04/24/2009	$300	7.25% Senior Secured Notes	2020	Repay short-term borrowings, fund capital expenditures and other general purposes
Penn	06/30/2009	$100	6.09% FMB	2022	Fund capital expenditures and repurchase equity from OE
* Issuance was sold off the shelf registration statement referenced above.

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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. In preparing the financial statements, FirstEnergy and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through August 3, 2009, the date the financial statements were issued.

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, 2008 for FirstEnergy, FES and the Utilities. The consolidated unaudited financial statements of FirstEnergy, FES and each of the Utilities 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 6) 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, 2009 and for the three-month and six-month periods ended June 30, 2009 and 2008, have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their report (dated August 3, 2009) 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 are 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 following table reconciles basic and diluted earnings per share of common stock:

	Three Months				Six Months
Reconciliation of Basic and Diluted Earnings per Share	Ended June 30				Ended June 30
of Common Stock	2009		2008		2009		2008
	(In millions, except per share amounts)
Earnings available to FirstEnergy Corp.	$	414	$	263	$	533	$	539
Average shares of common stock outstanding - Basic		304		304		304		304
Assumed exercise of dilutive stock options and awards		1		3		2		3
Average shares of common stock outstanding - Diluted		305		307		306		307
Basic earnings per share of common stock	$	1.36	$	0.86	$	1.75	$	1.77
Diluted earnings per share of common stock	$	1.36	$	0.85	$	1.75	$	1.75

110

Earnings in the second quarter of 2009 include a gain of $254 million ($0.52 per share) from the sale of FirstEnergy’s nine percent interest in the stock and output of OVEC.

3. FAIR VALUE OF FINANCIAL INSTRUMENTS

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

All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value, in the caption "short-term borrowings." The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations as of June 30, 2009 and December 31, 2008:

	June 30, 2009				December 31, 2008
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
FirstEnergy	$	12,389	$	12,535	$	11,585	$	11,146
FES		2,556		2,559		2,552		2,528
OE		1,169		1,233		1,232		1,223
CEI		1,723		1,806		1,741		1,618
TE		600		621		300		244
JCP&L		1,856		1,873		1,569		1,520
Met-Ed		842		858		542		519
Penelec		679		676		779		721

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

(B) INVESTMENTS

All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include held-to-maturity securities and available-for-sale securities.

FES and the Utilities periodically evaluate their investments for other-than-temporary impairment. They first consider their intent and ability to hold an equity investment until recovery and then consider, among other factors, the duration and the extent to which the security's fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating an investment for impairment. For debt securities, in accordance with FSP FAS 115-2 and FAS 124-2, FES and the Utilities consider their intent to hold the security, the likelihood that they will be required to sell the security before recovery of its cost basis, and the likelihood of recovery of the security's entire amortized cost basis.

Available-For-Sale Securities

FES and the Utilities hold debt and equity securities within their nuclear decommissioning trusts, nuclear fuel disposal trusts and NUG trusts. These trust investments are classified as available-for-sale with the fair value representing quoted market prices. FES and the Utilities have no securities held for trading purposes.

The following table summarizes the amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities as of June 30, 2009 and December 31, 2008:

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	June 30, 2009(1)								December 31, 2008(2)
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
Debt securities	(In millions)
FirstEnergy(3)	$	1,181	$	44	$	-	$	1,225	$	1,078	$	56	$	-	$	1,134
FES		476		25		-		501		401		28		-		429
OE		93		3		-		96		86		9		-		95
TE		70		3		-		73		66		8		-		74
JCP&L		249		7		-		256		249		9		-		258
Met-Ed		116		3		-		119		111		4		-		115
Penelec		178		3		-		181		164		3		-		167
Equity securities
FirstEnergy	$	512	$	76	$	-	$	588	$	589	$	39	$	-	$	628
FES		275		55		-		330		355		25		-		380
OE		15		3		-		18		17		1		-		18
JCP&L		65		4		-		69		64		2		-		66
Met-Ed		104		10		-		114		101		9		-		110
Penelec		53		4		-		57		51		2		-		53
(1) Excludes cash balances of $231 million at FirstEnergy, $209 million at FES, $14 million at JCP&L, $4 million at OE, $3 million at Penelec and $1 million at TE. (2) Excludes cash balances of $244 million at FirstEnergy, $225 million at FES, $12 million at Penelec, $4 million at OE and $1 million at Met-Ed. (3) Includes fair values as of June 30, 2009 and December 31, 2008 of $982 million and $953 million of government obligations, $238 million and $175 million of corporate debt and $5 million and $6 million of mortgage backed securities.

Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income as of June 30, 2009 were as follows:

	FirstEnergy		FES		OE		TE		JCP&L		Met-Ed		Penelec
	(In millions)
Proceeds from sales	$	1,001	$	537	$	25	$	77	$	245	$	63	$	54
Realized gains		30		24		-		3		3		1		-
Realized losses		91		58		3		-		11		12		7
Interest and dividend income		30		14		2		1		7		3		3

Unrealized gains applicable to the decommissioning trusts of OE, TE and FES are recognized in OCI in accordance with SFAS 115, as fluctuations in fair value will eventually impact earnings. The decommissioning trusts of JCP&L, Met-Ed and Penelec are subject to regulatory accounting in accordance with SFAS 71. Net unrealized gains and losses are recorded as regulatory assets or liabilities since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers.

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

Held-To-Maturity Securities

The following table provides the amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities except for investments of $271 million and $293 million excluded by SFAS 107 as of June 30, 2009 and December 31, 2008:

	June 30, 2009								December 31, 2008
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
Debt securities	(In millions)
FirstEnergy	$	627	$	51	$	-	$	678	$	673	$	14	$	13	$	674
OE		230		9		-		239		240		-		13		227
CEI		389		43		-		432		426		9		-		435

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The following table provides the approximate fair value and related carrying amounts of notes receivable as of June 30, 2009 and December 31, 2008:

	June 30, 2009				December 31, 2008
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Notes receivable	(In millions)
FirstEnergy	$	40	$	38	$	45	$	44
FES		6		6		75		74
OE		193		233		257		294
TE		161		184		180		189

The fair value of notes receivable represents the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. The maturity dates range from 2009 to 2040.

(C) RECURRING FAIR VALUE MEASUREMENTS

FirstEnergy's valuation techniques, including the three levels of the fair value hierarchy as defined by SFAS 157, are disclosed in Note 5 of the Notes to Consolidated Financial Statements in FirstEnergy's Annual Report on Form 10-K for the year ended December 31, 2008.

The following tables set forth financial assets and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of June 30, 2009 and December 31, 2008. 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 fair valuation of assets and liabilities and their placement within the fair value hierarchy levels.

Recurring Fair Value Measures as of June 30, 2009
		Level 1 - Assets                    (In millions)								Level 1 - Liabilities
		Derivatives		Available-for-Sale Securities(1)		Other Investments		Total		Derivatives		NUG Contracts(2)		Total
FirstEnergy	$	1	$	495	$	-	$	496	$	19	$	-	$	19
FES		1		237		-		238		19		-		19
OE		-		18		-		18		-		-		-
JCP&L		-		70		-		70		-		-		-
Met-Ed		-		109		-		109		-		-		-
Penelec		-		61		-		61		-		-		-
		Level 2 - Assets								Level 2 - Liabilities
		Derivatives		Available-for-Sale Securities(1)		Other Investments		Total		Derivatives		NUG Contracts(2)		Total
FirstEnergy	$	41	$	1,547	$	84	$	1,672	$	19	$	-	$	19
FES		21		800		-		821		15		-		15
OE		-		98		-		98		-		-		-
TE		-		73		-		73		-		-		-
JCP&L		5		270		-		275		-		-		-
Met-Ed		9		126		-		135		-		-		-
Penelec		5		179		-		184		-		-		-
		Level 3 - Assets								Level 3 - Liabilities
		Derivatives		Available-for-Sale Securities(1)		NUG Contracts(2)		Total		Derivatives		NUG Contracts(2)		Total
FirstEnergy	$	-	$	-	$	214	$	214	$	-	$	750	$	750
JCP&L		-		-		9		9		-		475		475
Met-Ed		-		-		184		184		-		161		161
Penelec		-		-		21		21		-		114		114

(1) Consists of investments in the nuclear decommissioning trusts, the spent nuclear fuel trusts and the NUG trusts. Balance excludes $2 million of receivables, payables and accrued income.

(2)    NUG contracts are completely offset by regulatory assets and do not impact earnings.

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Recurring Fair Value Measures as of December 31, 2008
		Level 1 – Assets                    (In millions)								Level 1 - Liabilities
		Derivatives		Available-for-Sale Securities(1)		Other Investments		Total		Derivatives		NUG Contracts(2)		Total
FirstEnergy	$	-	$	537	$	-	$	537	$	25	$	-	$	25
FES		-		290		-		290		25		-		25
OE		-		18		-		18		-		-		-
JCP&L		-		67		-		67		-		-		-
Met-Ed		-		104		-		104		-		-		-
Penelec		-		58		-		58		-		-		-
		Level 2 - Assets								Level 2 - Liabilities
		Derivatives		Available-for-Sale Securities(1)		Other Investments		Total		Derivatives		NUG Contracts(2)		Total
FirstEnergy	$	40	$	1,464	$	83	$	1,587	$	31	$	-	$	31
FES		12		744		-		756		28		-		28
OE		-		98		-		98		-		-		-
TE		-		73		-		73		-		-		-
JCP&L		7		255		-		262		-		-		-
Met-Ed		14		121		-		135		-		-		-
Penelec		7		174		-		181		-		-		-
		Level 3 - Assets								Level 3 - Liabilities
		Derivatives		Available-for-Sale Securities(1)		NUG Contracts(2)		Total		Derivatives		NUG Contracts(2)		Total
FirstEnergy	$	-	$	-	$	434	$	434	$	-	$	766	$	766
JCP&L		-		-		14		14		-		532		532
Met-Ed		-		-		300		300		-		150		150
Penelec		-		-		120		120		-		84		84

(1) Consists of investments in the nuclear decommissioning trusts, the spent nuclear fuel trusts and the NUG trusts. Balance excludes $5 million of receivables, payables and accrued income.

(2)    NUG contracts are completely offset by regulatory assets and do not impact earnings.

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

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, 2009 and 2008 (in millions):

	FirstEnergy			JCP&L			Met-Ed			Penelec
Balance as of January 1, 2009	$	(332	)	$	(518	)	$	150		$	36
Settlements(1)		179			90			43			47
Unrealized gains (losses)(1)		(383	)		(38	)		(170	)		(176	)
Net transfers to (from) Level 3		-			-			-			-
Balance as of June 30, 2009	$	(536	)	$	(466	)	$	23		$	(93	)
Change in unrealized gains (losses) relating to  instruments held as of June 30, 2009	$	(383	)	$	(38	)	$	(170	)	$	(176	)
Balance as of April 1, 2009	$	(476	)	$	(518	)	$	76		$	(34	)
Settlements(1)		96			44			26			27
Unrealized gains (losses)(1)		(156	)		8			(79	)		(86	)
Net transfers to (from) Level 3		-			-			-			-
Balance as of June 30, 2009	$	(536	)	$	(466	)	$	23		$	(93	)
Change in unrealized gains (losses) relating to instruments held as of June 30, 2009	$	(156	)	$	8		$	(79	)	$	(86	)

114

	FirstEnergy			JCP&L			Met-Ed			Penelec
Balance as of January 1, 2008	$	(803	)	$	(750	)	$	(28	)	$	(25	)
Settlements(1)		110			95			2			13
Unrealized gains (losses)(1)		676			11			376			290
Net transfers to (from) Level 3		-			-			-			-
Balance as of June 30, 2008	$	(17	)	$	(644	)	$	350		$	278
Change in unrealized gains (losses) relating to  instruments held as of June 30, 2008	$	676		$	11		$	376		$	290
Balance as of April 1, 2008	$	(419	)	$	(682	)	$	145		$	119
Settlements(1)		46			45			(3	)		5
Unrealized gains (losses)(1)		356			(7	)		208			154
Net transfers to (from) Level 3		-			-			-			-
Balance as of June 30, 2008	$	(17	)	$	(644	)	$	350		$	278
Change in unrealized gains (losses) relating to instruments held as of June 30, 2008	$	356		$	(7	)	$	208		$	154

 (1)  Changes in fair value of NUG contracts are completely offset by regulatory assets and do not impact earnings.

On January 1, 2009, FirstEnergy adopted FSP FAS 157-2, for financial assets and financial liabilities measured at fair value on a non-recurring basis. The impact of SFAS 157 on those financial assets and financial liabilities is immaterial.

4. DERIVATIVE INSTRUMENTS

FirstEnergy is exposed to financial risks resulting from fluctuating 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 for risk management purposes. In addition to derivatives, FirstEnergy also enters into master netting agreements with certain third parties. 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 Sheets at their fair value unless they meet the normal purchase 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 purchase and normal sales criteria are recorded as other expense, as AOCL, or as part of the value of the hedged item as described below.

Interest Rate Derivatives

Under the revolving credit facility, FirstEnergy incurs variable interest charges based on LIBOR. In 2008, FirstEnergy entered into swaps with a notional value of $300 million to hedge against changes in associated interest rates. Hedges with a notional value of $100 million expire in November 2009 and $100 million expire in November 2010. The swaps are accounted for as cash flow hedges under SFAS 133. As of June 30, 2009, the fair value of outstanding swaps was $(3) million.

FirstEnergy uses forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. During the first six months of 2009, FirstEnergy terminated forward swaps with a notional value of $100 million when a subsidiary issued long term debt. The gain associated with the termination was $1.3 million, of which $0.3 million was ineffective and recognized as an adjustment to interest expense. The remaining effective portion will be amortized to interest expense over the life of the hedged debt.

As of June 30, 2009 and December 31, 2008, the fair value of outstanding interest rate derivatives was $(3) million. Interest rate derivatives are included in "Other Noncurrent Liabilities" on FirstEnergy’s consolidated balance sheets. The effect of interest rate derivatives on the consolidated statements of income and comprehensive income during the three months and six months ended June 30, 2009 and 2008 were:

115

		Three Months						Six Months
		Ended June 30						Ended June 30
		2009			2008			2009			2008
		(In millions)
Effective Portion
	Gain Recognized in AOCL	$	2		$	-		$	-		$	-
	Loss Reclassified from AOCL into Interest Expense		(6	)		(3	)		(11	)		(7	)
Ineffective Portion
	Loss Recognized in Interest Expense		-			(4	)		-			(5	)

Total unamortized losses included in AOCL associated with prior interest rate hedges totaled $113 million ($68 million net of tax) as of June 30, 2009. Based on current estimates, approximately $9 million will be amortized to interest expense during the next twelve months. FirstEnergy’s interest rate swaps do not include any contingent credit risk related features.

Commodity Derivatives

FirstEnergy uses both physically and financially settled derivatives to manage its exposure to volatility in commodity prices. Commodity derivatives are used for risk management purposes to hedge exposures when it makes economic sense to do so, including circumstances in which the hedging relationship does not qualify for hedge accounting. Derivatives that do not qualify under the normal purchase or sales criteria or for hedge accounting as cash flow hedges are marked to market through earnings. FirstEnergy’s risk policy does not allow derivatives to be used for speculative or trading purposes. FirstEnergy hedges forecasted electric sales and purchases and anticipated natural gas purchases using forwards and options. Heating oil futures are used to hedge both oil purchases and fuel surcharges associated with rail transportation contracts. FirstEnergy’s maximum hedge term is typically two years. The effective portions of all cash flow hedges are initially recorded in AOCL and are subsequently included in net income as the underlying hedged commodities are delivered.

The following tables summarize the location and fair value of commodity derivatives in FirstEnergy’s Consolidated Balance Sheets:

Derivative Assets						Derivative Liabilities
			Fair Value							Fair Value
			June 30,		December 31,					June 30,		December 31,
			2009		2008					2009		2008
Cash Flow Hedges			(In millions)			Cash Flow Hedges				(In millions)
Electricity Forwards						Electricity Forwards
	Current Assets	$	21	$	11		Current Liabilities		$	15	$	27
Natural Gas Futures						Natural Gas Futures
	Current Assets		-		-		Current Liabilities			9		4
	Long-Term Deferred Charges		-		-		Noncurrent Liabilities			3		5
Other						Other
	Current Assets		-		-			Current Liabilities		7		12
	Long-Term Deferred Charges		-		-			Noncurrent Liabilities		4		4
		$	21	$	11				$	38	$	52
Derivative Assets						Derivative Liabilities
			Fair Value							Fair Value
			June 30, 2009		December 31, 2008					June 30, 2009		December 31, 2008
Economic Hedges			(In millions)			Economic Hedges				(In millions)
NUG Contracts						NUG Contracts
	Power Purchase							Power Purchase
	Contract Asset	$	214	$	434			Contract Liability	$	750	$	766
Other						Other
	Current Assets		2		1			Current Liabilities		-		1
	Long-Term Deferred Charges		19		28			Noncurrent Liabilities		-		-
		$	235	$	463				$	750	$	767
Total Commodity Derivatives		$	256	$	474	Total Commodity Derivatives			$	788	$	819

Electricity forwards are used to balance expected retail and wholesale sales with expected generation and purchased power. Natural gas futures are entered into based on expected consumption of natural gas, primarily used in FirstEnergy’s peaking units. Heating oil futures are entered into based on expected consumption of oil and the financial risk in FirstEnergy’s transportation contracts. Derivative instruments are not used in quantities greater than forecasted needs. The following table summarizes the volume of FirstEnergy’s outstanding derivative transactions as of June 30, 2009.

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	Purchases		Sales			Net			Units
	(In thousands)
Electricity Forwards		471		(3,735	)		(3,264	)	MWH
Heating Oil Futures		13,188		(1,260	)		11,928		Gallons
Natural Gas Futures		3,850		-			3,850		mmBtu

The effect of derivative instruments on the consolidated statements of income and comprehensive income for the three and six months ended June 30, 2009 and 2008, for instruments designated in cash flow hedging relationships and not in hedging relationships, respectively, are summarized in the following tables:

Derivatives in Cash Flow Hedging Relationships			Electricity			Natural Gas			Heating Oil
			Forwards			Futures			Futures			Total
Three Months Ended June 30, 2009			(in millions)
Gain (Loss) Recognized in AOCL (Effective Portion)		$	6		$	-		$	2		$	8
Effective Gain (Loss) Reclassified to:(1)
	Purchased Power Expense		1			-			-			1
	Fuel Expense		-			(4	)		(4	)		(8	)
Six Months Ended June 30, 2009
Gain (Loss) Recognized in AOCL (Effective Portion)		$	4		$	(7	)	$	1		$	(2	)
Effective Gain (Loss) Reclassified to:(1)
	Purchased Power Expense		(17	)		-			-			(17	)
	Fuel Expense		-			(4	)		(8	)		(12	)
Three Months Ended June 30, 2008
Gain (Loss) Recognized in AOCL (Effective Portion)		$	(16	)	$	3		$	-		$	(13	)
Effective Gain (Loss) Reclassified to:(1)
	Purchased Power Expense		4			-			-			4
	Fuel Expense		-			1			-			1
Six Months Ended June 30, 2008
Gain (Loss) Recognized in AOCL (Effective Portion)		$	(30	)	$	6		$	-		$	(24	)
Effective Gain (Loss) Reclassified to:(1)
	Purchased Power Expense		(13	)		-			-			(13	)
	Fuel Expense		-			1			-			1
(1) The ineffective portion was immaterial.

		Three Months Ended June 30									Six Months Ended June 30
Derivatives Not in Hedging Relationships			NUG									NUG
			Contracts			Other			Total			Contracts			Other			Total
2009		(In millions)
Unrealized Gain (Loss) Recognized in:
Fuel Expense(1)		$	-		$	2		$	2		$	-		$	2		$	2
Regulatory Assets(2)			(156	)		-			(156	)		(383	)		-			(383	)
		$	(156	)	$	2		$	(154	)	$	(383	)	$	2		$	(381	)
Realized Gain (Loss) Reclassified to:
Fuel Expense(1)		$	-		$	-		$	-		$	-		$	(1	)	$	(1	)
Regulatory Assets(2)			(96	)		-			(96	)		(179	)		10			(169	)
		$	(96	)	$	-		$	(96	)	$	(179	)	$	9		$	(170	)
2008
Unrealized Gain (Loss) Recognized in:
Regulatory Assets(2)		$	356		$	-		$	356		$	676		$	-		$	676
Realized Gain (Loss) Reclassified to:
Regulatory Assets(2)		$	(46	)	$	(1	)	$	(47	)	$	(110	)	$	10		$	(100	)
(1)	The realized gain (loss) is reclassified upon termination of the derivative instrument.
(2)	Changes in the fair value of NUG contracts are deferred for future recovery from (or refund to) customers.

Total unamortized losses included in AOCL associated with commodity derivatives were $17 million ($10 million net of tax) as of June 30, 2009, as compared to $44 million ($27 million net of tax) as of December 31, 2008. The net of tax change resulted from a net $1 million decrease related to current hedging activity and a $16 million decrease due to net hedge losses reclassified to earnings during the first six months of 2009. Based on current estimates, approximately $6 million (after tax) of the net deferred losses on derivative instruments in AOCL as of June 30, 2009 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.

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Many of FirstEnergy’s commodity derivatives contain credit risk features. As of June 30, 2009, FirstEnergy posted $133 million of collateral related to net liability positions and held no counterparties’ funds related to asset positions. The collateral FirstEnergy has posted relates to both derivative and non-derivative contracts. FirstEnergy’s largest derivative counterparties fully collateralize all derivative transactions. Certain commodity derivative contracts include credit-risk-related contingent features that would require FirstEnergy to post additional collateral if the credit rating for its debt were to fall below investment grade. The aggregate fair value of derivative instruments with credit-risk related contingent features that are in a liability position on June 30, 2009 was $1 million, for which no collateral has been posted. If FirstEnergy’s credit rating were to fall below investment grade, it would be required to post $19 million of additional collateral related to commodity derivatives.

5. PENSION AND OTHER POSTRETIREMENT BENEFITS

FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The 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. 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.

On June 2, 2009, FirstEnergy amended its health care benefits plan (Plan) for all employees and retirees eligible to participate in the Plan. The Plan amendment, which reduces future health care coverage subsidies paid by FirstEnergy on behalf of participants, triggered a remeasurement of FirstEnergy’s other postretirement benefit plans as of May 31, 2009. As a result of the remeasurement, the Plan’s discount rate was revised to 7.5% while the expected long-term rate of return on assets remained at 9%. The remeasurement and Plan amendment increased FirstEnergy’s accumulated other comprehensive income by $449 million in the second quarter of 2009 and will reduce FirstEnergy’s net postretirement benefit cost (including amounts capitalized) for the remainder of 2009 by $48 million, including a $7 million reduction that is applicable to the second quarter of 2009.

FirstEnergy’s net pension and OPEB expenses (benefits) for the three months ended June 30, 2009 and 2008 were $38 million and $(15) million, respectively. For the six months ended June 30, 2009 and 2008, FirstEnergy’s net pension and OPEB expenses (benefits) were $80 million and $(29) million, respectively. The components of FirstEnergy's net pension and other postretirement benefit costs (including amounts capitalized) for the three months and six months ended June 30, 2009 and 2008, consisted of the following:

	Three Months						Six Months
	Ended June 30						Ended June 30
Pension Benefits	2009			2008			2009			2008
	(In millions)
Service cost	$	22		$	22		$	43		$	43
Interest cost		80			75			159			150
Expected return on plan assets		(81	)		(116	)		(162	)		(231	)
Amortization of prior service cost		3			3			7			6
Recognized net actuarial loss		42			2			85			4
Net periodic cost (credit)	$	66		$	(14	)	$	132		$	(28	)

	Three Months						Six Months
	Ended June 30						Ended June 30
Other Postretirement Benefits	2009			2008			2009			2008
	(In millions)
Service cost	$	4		$	5		$	8		$	9
Interest cost		18			18			38			37
Expected return on plan assets		(9	)		(13	)		(18	)		(26	)
Amortization of prior service cost		(41	)		(37	)		(79	)		(74	)
Recognized net actuarial loss		15			12			31			24
Net periodic cost (credit)	$	(13	)	$	(15	)	$	(20	)	$	(30	)

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Pension and postretirement benefit obligations are allocated to FirstEnergy's subsidiaries employing the plan participants. FES and the Utilities 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 Utilities for the three months and six months ended June 30, 2009 and 2008 were as follows:

	Three Months					Six Months
	Ended June 30					Ended June 30
Pension Benefit Cost (Credit)	2009		2008			2009		2008
	(In millions)
FES	$	18	$	5		$	36	$	11
OE		7		(6	)		14		(12	)
CEI		5		(1	)		10		(2	)
TE		2		(1	)		3		(1	)
JCP&L		9		(3	)		18		(7	)
Met-Ed		6		(2	)		11		(5	)
Penelec		4		(3	)		9		(6	)
Other FirstEnergy subsidiaries		15		(3	)		31		(6	)
	$	66	$	(14	)	$	132	$	(28	)

	Three Months						Six Months
	Ended June 30						Ended June 30
Other Postretirement Benefit Cost (Credit)	2009			2008			2009			2008
	(In millions)
FES	$	(3	)	$	(2	)	$	(4	)	$	(4	)
OE		(3	)		(2	)		(5	)		(3	)
CEI		-			1			1			1
TE		-			1			1			2
JCP&L		(1	)		(4	)		(2	)		(8	)
Met-Ed		(1	)		(3	)		(2	)		(5	)
Penelec		(1	)		(3	)		(2	)		(6	)
Other FirstEnergy subsidiaries		(4	)		(3	)		(7	)		(7	)
	$	(13	)	$	(15	)	$	(20	)	$	(30	)

6. VARIABLE INTEREST ENTITIES

FirstEnergy and its subsidiaries consolidate VIEs when they are determined to be the VIE's primary beneficiary as defined by FIN 46R. Effective January 1, 2009, FirstEnergy adopted SFAS 160. As a result, FirstEnergy and its subsidiaries reflect the portion of VIEs not owned by them in the caption noncontrolling interest within the consolidated financial statements. The change in noncontrolling interest within the consolidated balance sheets is the result of earnings and losses of the noncontrolling interests and distribution to owners.

Mining Operations

On July 16, 2008, FEV entered into a joint venture with the Boich Companies, a Columbus, Ohio-based coal company, to acquire a majority stake in the Signal Peak mining and coal transportation operations near Roundup, Montana. FEV made a $125 million equity investment in the joint venture, which acquired 80% of the mining operations (Signal Peak Energy, LLC) and 100% of the transportation operations, with FEV owning a 45% economic interest and an affiliate of the Boich Companies owning a 55% economic interest in the joint venture. Both parties have a 50% voting interest in the joint venture. In March 2009, FEV agreed to pay a total of $8.5 million to affiliates of the Boich Companies to purchase an additional 5% economic interest in the Signal Peak mining and coal transportation operations. Voting interests remained unchanged after the sale was completed in July 2009. Effective January 16, 2010, the joint venture will have 18 months to exercise an option to acquire the remaining 20% stake in the mining operations. In accordance with FIN 46R, FEV consolidates the mining and transportation operations of this joint venture in its financial statements.

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.

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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 for the purchase of lease obligation bonds. 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.

Loss Contingencies

FES and the Ohio Companies are exposed to losses under their applicable sale-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 were made. The following table discloses each company's net exposure to loss based upon the casualty value provisions mentioned above:

	Maximum Exposure		Discounted Lease Payments, net(1)		Net Exposure
	(In millions)
FES	$	1,347	$	1,172	$	175
OE	749		549		200
CEI	703		74		629
TE	703		376		327

(1)  The net present value of FirstEnergy's consolidated sale and leaseback operating

     lease commitments is $1.7 billion

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 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.

During the second quarter of 2008, NGC purchased 56.8 MW of lessor equity interests in the OE 1987 sale and leaseback of the Perry Plant and approximately 43.5 MW of lessor equity interests in the OE 1987 sale and leaseback of Beaver Valley Unit 2. In addition, NGC purchased 158.5 MW of lessor equity interests in the TE and CEI 1987 sale and leaseback of Beaver Valley Unit 2. The Ohio Companies continue to lease these MW under their 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 Utilities 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 25 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.

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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. As of June 30, 2009, the net above-market loss liability projected for these eight NUG agreements was $9 million. Purchased power costs from these entities during the three months ended June 30, 2009 and 2008 are shown in the following table:

	Three Months				Six Months
	Ended June 30				Ended June 30
	2009		2008		2009		2008
	(In millions)
JCP&L	$	18	$	22	$	37	$	41
Met-Ed		13		16		28		32
Penelec		8		8		17		17
Total	$	39	$	46	$	82	$	90

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, 2009, $356 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.

7. INCOME TAXES

FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements in accordance with FIN 48. 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. Upon completion of the federal tax examination for the 2007 tax year in the first quarter of 2009, FirstEnergy recognized $13 million in tax benefits, which favorably affected FirstEnergy's effective tax rate. During the second quarter of 2009 and the first six months of 2008, there were no material changes to FirstEnergy's unrecognized tax benefits. As of June 30, 2009, FirstEnergy expects that it is reasonably possible that $195 million of unrecognized benefits may be resolved within the next twelve months, of which approximately $148 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, 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. The net amount of accumulated interest accrued as of June 30, 2009 was $64 million, as compared to $59 million as of December 31, 2008. During the first six months of 2009 and 2008, there were no material changes to the amount of interest accrued.

In 2008, FirstEnergy, on behalf of FGCO and NGC, filed a change in accounting method related to the costs to repair and maintain electric generation stations. During the second quarter of 2009, the IRS approved the change in accounting method and FGCO and NGC are in the process of computing the amount of costs that will qualify as a deduction. If the IRS completes its review process by the extended filing date of September 15, 2009, an amount for the repair deduction will be included in FirstEnergy’s 2008 consolidated tax return. This change in accounting method could have a significant impact on taxable income for 2008 and could reduce the amount of taxes to be accrued in the third quarter of 2009, with no corresponding impact to the effective tax rate for the quarter.

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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 2001-2008. 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 were completed in 2008 and several items are under appeal. The IRS began auditing the year 2007 in February 2007 under its Compliance Assurance Process program and was completed in the first quarter of 2009 with two items under appeal. The IRS began auditing the year 2008 in February 2008 and the year 2009 in February 2009 under its Compliance Assurance Process program. Neither audit is expected to close before December 2009. 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.

8. 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, 2009, outstanding guarantees and other assurances aggregated approximately $4.6 billion, consisting primarily of parental guarantees - $1.3 billion, subsidiaries’ guarantees - $2.6 billion, surety bonds - $0.1 billion and LOCs - $0.5 billion.

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge 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 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 $1.3 billion discussed above) as of June 30, 2009 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, provision of an LOC or accelerated payments may be required of the subsidiary. As of June 30, 2009, FirstEnergy's maximum exposure under these collateral provisions was $601 million, consisting of $41 million due to “material adverse event” contractual clauses and $560 million due to a below investment grade credit rating. Additionally, stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase this amount to $700 million, consisting of $49 million due to “material adverse event” contractual clauses and $651 million due to a below investment grade credit rating.

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $108 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 addition to guarantees and surety bonds, FES’ contracts, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions which require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ contracts as of June 30, 2009, and forward prices as of that date, FES had $179 million of outstanding collateral payments. Under a hypothetical adverse change in forward prices (15% decrease in the first 12 months and 20% decrease in prices thereafter), FES would be required to post an additional $73 million. Depending on the volume of forward contracts entered and future price movements, FES could be required to post significantly higher amounts for margining.

In July 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has fully and irrevocably guaranteed all of FGCO’s obligations under each of the leases (see Note 12). 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.

On October 8, 2008, to enhance their liquidity position in the face of the turbulent credit and bond markets, FirstEnergy, FES and FGCO entered into a $300 million secured term loan facility with Credit Suisse. Under the facility, FGCO is the borrower and FES and FirstEnergy are guarantors. Generally, the facility is available to FGCO until October 7, 2009, with a minimum borrowing amount of $100 million and maturity 30 days from the date of the borrowing. Once repaid, borrowings may not be re-borrowed.

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In connection with FES’ obligations to post and maintain collateral under the two-year PSA entered into by FES and the Ohio Companies following the CBP auction on May 13-14, 2009, NGC entered into a Surplus Margin Guaranty in the amount of approximately $500 million, dated as of June 16, 2009, in favor of the Ohio Companies.

FES’ debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC, pursuant to guarantees entered into on March 26, 2007. Similar guarantees were entered into on that date pursuant to which FES guaranteed the debt obligations of each of FGCO and NGC.  Accordingly, present and future holders of indebtedness of FES, FGCO and NGC will have claims against each of FES, FGCO and NGC regardless of whether their primary obligor is FES, FGCO or NGC.

(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 $808 million for the period 2009-2013.

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 $37,500 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, the generation of more electricity at lower-emitting plants, and/or using emission allowances. 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.

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 and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s 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 was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices or repowering and provides for stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree, including repowering Burger Units 4 and 5 for biomass fuel consumption, are currently estimated to be $706 million for 2009-2012 (with $414 million expected to be spent in 2009).

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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. In July 2008, three additional complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania 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. On October 14, 2008, the Court granted FGCO’s motion to consolidate discovery for all four complaints pending against the Bruce Mansfield Plant. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints. The Pennsylvania Department of Health, under a Cooperative Agreement with the Agency for Toxic Substances and Disease Registry, completed a Health Consultation regarding the Mansfield Plant and issued a report dated March 31, 2009 which concluded there is insufficient sampling data to determine if any public health threat exists for area residents due to emissions from the Mansfield Plant. The report recommended additional air monitoring and sample analysis in the vicinity of the Mansfield Plant which the Pennsylvania Department of Environmental Protection is currently conducting.

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.  On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. Specifically, Connecticut and New Jersey allege that "modifications" at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed.  On December 5, 2008, New Jersey filed an amended complaint, adding claims with respect to alleged modifications that occurred after GPU’s sale of the plant. Met-Ed filed a Motion to Dismiss the claims in New Jersey’s Amended Complaint and Connecticut’s Complaint on February 19, 2009. On January 14, 2009, the EPA issued a NOV to Reliant alleging new source review violations at the Portland Generation Station based on “modifications” dating back to 1986. Met-Ed is unable to predict the outcome of this matter. The EPA’s January 14, 2009, NOV also alleged new source review violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of Keystone Station and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter. On June 1, 2009, the Court held oral argument on Met-Ed’s motion to dismiss the complaint.

On June 11, 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. 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. Mission Energy is seeking indemnification from Penelec, 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. The scope of Penelec’s indemnity obligation to and from Mission Energy 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 Administrative Consent Order modifying that request and setting forth a schedule for FGCO’s response. On October 27, 2008, FGCO received a second request from the EPA for information pursuant to Section 114(a) of the CAA for additional operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants. FGCO intends to fully comply with the EPA’s information requests, but, at this time, is unable to predict the outcome of this matter.

On August 18, 2008, FirstEnergy received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding its formerly-owned Avon Lake and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. FirstEnergy intends to fully comply with the EPA’s information request, 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 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 requires 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 2.5 million tons annually and NOX emissions to 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.” On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. On December 23, 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s July 11, 2008 opinion. On July 10, 2009, the United States Court of Appeals for the District of Columbia ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOX SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the "8-hour" ozone NAAQS. FGCO's future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA 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. On October 17, 2008, the EPA (and an industry group) petitioned the United States Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the EPA moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the EPA’s petition and denied the industry group’s petition. The EPA is developing 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 any future regulations 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. On January 30, 2009, the Commonwealth Court of Pennsylvania declared Pennsylvania’s mercury rule “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule. It is anticipated that compliance with these regulations, if the Commonwealth Court’s rulings were reversed on appeal and Pennsylvania’s mercury rule was 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.

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, by 2012, the amount of man-made GHG, including CO2, emitted by developed countries. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. 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. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity used in the United States comes from renewable sources by 2012, increasing to 25% by 2025, and implementing an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050.

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 House of Representatives passed one such bill, the American Clean Energy and Security Act of 2009, on June 26, 2009. 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.

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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 April 17, 2009, the EPA released a “Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s proposed finding concludes that the atmospheric concentrations of several key greenhouse gases threaten the health and welfare of future generations and that the combined emissions of these gases by motor vehicles contribute to the atmospheric concentrations of these key greenhouse gases and hence to the threat of climate change. Although the EPA’s proposed finding, if finalized, does not establish emission requirements for motor vehicles, such requirements would be expected to occur through further rulemakings. Additionally, while the EPA’s proposed findings do not specifically address stationary sources, including electric generating plants, those findings, if finalized, would be expected to support the establishment of future emission requirements by the EPA for stationary sources.

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 1, 2009, the Supreme Court of the United States reversed one significant aspect of the Second Circuit Court’s opinion and decided that 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 and 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.

The U.S. Attorney's Office in Cleveland, Ohio has advised FGCO that it is considering prosecution under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007. FGCO is unable to predict the outcome of this matter.

Regulation of Waste Disposal

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. In February 2009, the EPA requested comments from the states on options for regulating coal combustion wastes, including regulation as non-hazardous waste or regulation as a hazardous waste. In March and June 2009, the EPA requested information from FGCO’s Bruce Mansfield Plant regarding the management of coal combustion wastes. FGCO's future cost of compliance with any coal combustion waste regulations which may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the states.

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The Utilities have been named as potentially responsible parties 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 potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the consolidated balance sheet as of June 30, 2009, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $104 million (JCP&L - - $77 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through June 30, 2009. Included in the total are accrued liabilities of approximately $68 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

(C)           OTHER LEGAL PROCEEDINGS

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.  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 due to the outages.

After various motions, rulings and appeals, the Plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability, and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. The class was decertified twice by the trial court, and appealed both times by the Plaintiffs, with the results being that: (1) the Appellate Division limited the class only 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 which resulted in planned and unplanned outages in the area during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. On March 31, 2009, the trial court again granted JCP&L’s motion to decertify the class. On April 20, 2009, the Plaintiffs filed a motion for leave to take an interlocutory appeal to the trial court's decision to decertify the class, which was granted by the Appellate Division on June 15, 2009. According to the scheduling order issued by the Appellate Division, Plaintiffs' opening brief is due on August 25, 2009, JCP&L's opposition brief is due on September 25, 2009, and Plaintiffs' reply is due on October 5, 2009.

Nuclear Plant Matters

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. On June 8, 2009, the NRC issued the final Safety Evaluation Report (SER) supporting the renewed license for Beaver Valley Units 1 and 2. On July 8, 2009, the NRC’s Advisory Committee on Reactor Safeguards (ACRS) held a public meeting to consider the NRC’s final SER. Much of the ACRS’ discussion involved questions raised by a letter from Citizens Power regarding the extent of corrective actions for the 2009 discovery of a penetration in the Beaver Valley Unit 1 containment liner. On July 28, 2009, FENOC submitted to the NRC further clarifications on the supplemental volumetric examinations of Beaver Valley’s containment liners. FENOC anticipates another meeting with the ACRS regarding the container liner during September 2009. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and is scheduled 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.

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Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of June 30, 2009, FirstEnergy had approximately $1.7 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 provided an additional $80 million parental guarantee associated with the funding of decommissioning costs for these units and indicated that it planned to contribute an additional $80 million to these trusts by 2010.  As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s obligations to fund the trusts may increase. The recent disruption in the capital markets and its effects on particular businesses and the economy in general also affects the values of the nuclear decommission trusts. On June 18, 2009, the NRC informed FENOC that its review tentatively concluded that a shortfall ($147.5 million net present value) existed in the value of the decommissioning trust fund for Beaver Valley Unit 1. On July 28, 2009, FENOC submitted a letter to the NRC that stated reasonable assurance of decommissioning funding is provided for Beaver Valley Unit 1 through a combination of the existing trust fund balances, the existing $80 million parental guarantee from FirstEnergy and maintaining the plant in a safe-store configuration, or extended safe shutdown condition, after plant shutdown. Renewal of the operating license for Beaver Valley Unit 1, as described above, would mitigate the estimated shortfall in the unit’s nuclear decommissioning funding status. FENOC continues to communicate with the NRC regarding future actions to provide reasonable assurance for decommissioning funding. Such actions may include additional parental guarantees or contributions to those funds.

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.

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. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. A final order identifying the individual damage amounts was issued on October 31, 2007 and 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 and oral arguments were held in the fall. On February 25, 2009, the federal district court denied JCP&L’s motion to vacate the arbitration decision and granted the union’s motion to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009. The appeal process could take as long as 24 months. JCP&L recognized a liability for the potential $16 million award in 2005. Post-judgment interest began to accrue as of February 25, 2009, and the liability will be adjusted accordingly.

The bargaining unit employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. On July 24, 2009, FirstEnergy declared that bargaining was at an impasse and portions of its last contract offer were implemented August 1, 2009.  A federal mediator is continuing to assist the parties in reaching a negotiated contract settlement. FirstEnergy has a strike mitigation plan ready in the event of a strike.

On May 21, 2009, 517 Penelec employees, represented by the International Brotherhood of Electrical Workers (IBEW) Local 459, elected to strike. In response, on May 22, 2009, Penelec implemented its work-continuation plan to use nearly 400 non-represented employees with previous line experience and training drawn from Penelec and other FirstEnergy operations to perform service reliability and priority maintenance work in Penelec’s service territory. Penelec's IBEW Local 459 employees ratified a three-year contract agreement on July 19, 2009, and returned to work on July 20, 2009.

On June 26, 2009, FirstEnergy announced that seven of its union locals, representing about 2,600 employees, have ratified contract extensions. These unions include employees from Penelec, Penn, CEI, OE and TE, along with certain power plant employees.

On July 8, 2009, FirstEnergy announced that employees of Met-Ed represented by IBEW Local 777 ratified a two-year contract. Union members had been working without a contract since the previous agreement expired on April 30, 2009.

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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9. REGULATORY MATTERS

(A) RELIABILITY INITIATIVES

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 Utilities 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 MISO region and found it to be in full compliance with all audited reliability standards. Similarly, in October 2008, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the PJM region and found it to be in full compliance with all audited reliability standards.

On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations, with customers in the affected area losing power. Power was restored to most customers within a few hours and to all customers within eleven hours. On December 16, 2008, JCP&L provided preliminary information about the event to certain regulatory agencies, including the NERC. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. The initial phase of the investigation requires JCP&L to respond to the NERC’s request for factual data about the outage. JCP&L submitted its written response on May 1, 2009. The NERC conducted on site interviews with personnel involved in responding to the event on June 16-17, 2009. On July 7, 2009, the NERC issued additional questions regarding the event and JCP&L is required to reply by August 7, 2009. JCP&L is not able at this time to predict what actions, if any, that the NERC may take based on the data submittal or interview results.

On June 5, 2009, FirstEnergy self-reported to ReliabilityFirst a potential violation of NERC Standard PRC-005 resulting from its inability to validate maintenance records for 20 protection system relays in JCP&L’s and Penelec’s transmission systems. These potential violations were discovered during a comprehensive field review of all FirstEnergy substations to verify equipment and maintenance database accuracy. FirstEnergy has completed all mitigation actions, including calibrations and maintenance records for the relays. ReliabilityFirst issued an Initial Notice of Alleged Violation on June 22, 2009. FirstEnergy is not able at this time to predict what actions or penalties, if any, that ReliabilityFirst will propose for this self-report of violation.

(B) OHIO

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. On January 21, 2009, the PUCO granted the Ohio Companies’ application to increase electric distribution rates by $136.6 million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million). These increases went into effect for OE and TE on January 23, 2009, and for CEI on May 1, 2009. Applications for rehearing of this order were filed by the Ohio Companies and one other party on February 20, 2009. The PUCO granted these applications for rehearing on March 18, 2009 for the purpose of further consideration. The PUCO has not yet issued a substantive Entry on Rehearing.

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SB221, which became effective on July 31, 2008, required all electric utilities to file an ESP, and permitted the filing of an MRO. On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and a separate MRO. The PUCO denied the MRO application; however, the PUCO later granted the Ohio Companies’ application for rehearing for the purpose of further consideration of the matter, which is still pending. The ESP proposed to phase in new generation rates for customers beginning in 2009 for up to a three-year period and resolve the Ohio Companies’ collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. In response to the PUCO’s December 19, 2008 order, which significantly modified and approved the ESP as modified, the Ohio Companies notified the PUCO that they were withdrawing and terminating the ESP application in addition to continuing their current rate plan in effect as allowed by the terms of SB221. On December 31, 2008, the Ohio Companies conducted a CBP for the procurement of electric generation for retail customers from January 5, 2009 through March 31, 2009. The average winning bid price was equivalent to a retail rate of 6.98 cents per KWH. The power supply obtained through this process provided generation service to the Ohio Companies’ retail customers who chose not to shop with alternative suppliers. On January 9, 2009, the Ohio Companies requested the implementation of a new fuel rider to recover the costs resulting from the December 31, 2008 CBP. The PUCO ultimately approved the Ohio Companies’ request for a new fuel rider to recover increased costs resulting from the CBP but denied OE’s and TE’s request to continue collecting RTC and denied the request to allow the Ohio Companies to continue collections pursuant to the two existing fuel riders. The new fuel rider recovered the increased purchased power costs for OE and TE, and recovered a portion of those costs for CEI, with the remainder being deferred for future recovery.

On January 29, 2009, the PUCO ordered its Staff to develop a proposal to establish an ESP for the Ohio Companies. On February 19, 2009, the Ohio Companies filed an Amended ESP application, including an attached Stipulation and Recommendation that was signed by the Ohio Companies, the Staff of the PUCO, and many of the intervening parties. Specifically, the Amended ESP provided that generation would be provided by FES at the average wholesale rate of the CBP process described above for April and May 2009 to the Ohio Companies for their non-shopping customers; for the period of June 1, 2009 through May 31, 2011, retail generation prices would be based upon the outcome of a descending clock CBP on a slice-of-system basis. The Amended ESP further provided that the Ohio Companies will not seek a base distribution rate increase, subject to certain exceptions, with an effective date of such increase before January 1, 2012, that CEI would agree to write-off approximately $216 million of its Extended RTC balance, and that the Ohio Companies would collect a delivery service improvement rider at an overall average rate of $.002 per KWH for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addressed a number of other issues, including but not limited to, rate design for various customer classes, and resolution of the prudence review and the collection of deferred costs that were approved in prior proceedings. On February 26, 2009, the Ohio Companies filed a Supplemental Stipulation, which was signed or not opposed by virtually all of the parties to the proceeding, that supplemented and modified certain provisions of the February 19, 2009 Stipulation and Recommendation. Specifically, the Supplemental Stipulation modified the provision relating to governmental aggregation and the Generation Service Uncollectible Rider, provided further detail on the allocation of the economic development funding contained in the Stipulation and Recommendation, and proposed additional provisions related to the collaborative process for the development of energy efficiency programs, among other provisions. The PUCO adopted and approved certain aspects of the Stipulation and Recommendation on March 4, 2009, and adopted and approved the remainder of the Stipulation and Recommendation and Supplemental Stipulation without modification on March 25, 2009. Certain aspects of the Stipulation and Recommendation and Supplemental Stipulation took effect on April 1, 2009 while the remaining provisions took effect on June 1, 2009.

On July 27, 2009, the Ohio Companies filed applications with the PUCO to recover three different categories of deferred distribution costs on an accelerated basis. In the Ohio Companies' Amended ESP, the PUCO approved the recovery of these deferrals, with collection originally set to begin in January 2011 and to continue over a 5 or 25 year period. The principal amount plus carrying charges through August 31, 2009 for these deferrals is a total of $298.4 million. If the applications are approved, recovery of this amount, together with carrying charges calculated as approved in the Amended ESP, will be collected in the 18 non-summer months from September 2009 through May 2011, subject to reconciliation until fully collected, with $165 million of the above amount being recovered from residential customers, and $133.4 million being recovered from non-residential customers. Pursuant to the applications, customers would pay significantly less over the life of the recovery of the deferral through the reduction in carrying charges as compared to the expected recovery under the previously approved recovery mechanism.

The Ohio Companies are presently involved in collaborative efforts related to energy efficiency and a competitive bidding process, together with other implementation efforts arising out of the Supplemental Stipulation. The CBP auction occurred on May 13-14, 2009, and resulted in a weighted average wholesale price for generation and transmission of 6.15 cents per KWH. The bid was for a single, two-year product for the service period from June 1, 2009 through May 31, 2011. FES participated in the auction, winning 51% of the tranches (one tranche equals one percent of the load supply). Subsequent to the signing of the wholesale contracts, two winning bidders reached separate agreements with FES to assign a total of 11 tranches to FES for various periods. In addition, FES has separately contracted with numerous communities to provide retail generation service through governmental aggregation programs.

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SB221 also requires electric distribution utilities to implement energy efficiency programs that achieve a total annual energy savings equivalent of approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013. Utilities are also required to reduce peak demand in 2009 by 1%, with an additional seventy-five hundredths of one percent reduction each year thereafter through 2018. Additionally, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they serve in 2009. FirstEnergy has efforts underway to address compliance with these requirements. Costs associated with compliance are recoverable from customers.

On June 17, 2009, the PUCO modified rules that implement the alternative energy portfolio standards created by SB221, including the incorporation of energy efficiency requirements, long-term forecast and greenhouse gas reporting and CO2 control planning. The PUCO filed the rules with the Joint Committee on Agency Rule Review on July 7, 2009, after which begins a 65-day review period. The Ohio Companies and one other party filed applications for rehearing on the rules with the PUCO on July 17, 2009.

(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. 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. 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. See FERC Matters below for a description of the Third Restated Partial Requirements Agreement, executed by the parties on October 31, 2008, that limits the amount of energy and capacity FES must supply to Met-Ed and Penelec. In the event of a third party supplier default, the increased costs to Met-Ed and Penelec could be material.

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 those filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing Met-Ed 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. Hearings and briefing for both Met-Ed and Penelec have concluded and the companies are awaiting a Recommended Decision from the ALJ. The TSCs included a component from under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for 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 May 28, 2009, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the period June 1, 2009 through May 31, 2010, as required in connection with the PPUC’s January 2007 rate order. For Penelec’s customers the new TSC resulted in an approximate 1% decrease in monthly bills, reflecting projected PJM transmission costs as well as a reconciliation for costs already incurred. The TSC for Met-Ed’s customers increased to recover the additional PJM charges paid by Met-Ed in the previous year and to reflect updated projected costs. In order to gradually transition customers to the higher rate, the PPUC approved Met-Ed’s proposal to continue to recover the prior period deferrals allowed in the PPUC’s May 2008 Order and defer $57.5 million of projected costs to a future TSC to be fully recovered by December 31, 2010. Under this proposal, monthly bills for Met-Ed’s customers will increase approximately 9.4% for the period June 2009 through May 2010.

On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law which became effective on November 14, 2008 as Act 129 of 2008. Act 129 addresses issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Major provisions of the legislation include:

·   power acquired by utilities to serve customers after rate caps expire will be procured through a competitive procurement process that must include a prudent mix of long-term and short-term contracts and spot market purchases;

·   the competitive procurement process must be approved by the PPUC and may include auctions, RFPs, and/or bilateral agreements;

·   utilities must provide for the installation of smart meter technology within 15 years;

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·   utilities must reduce peak demand by  a minimum of 4.5% by May 31, 2013;

·   utilities must reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively; and

·   the definition of Alternative Energy was expanded to include additional types of hydroelectric and biomass facilities.

Act 129 requires utilities to file with the PPUC an energy efficiency and peak load reduction plan by July 1, 2009, and a smart meter procurement and installation plan by August 14, 2009. On January 15, 2009, in compliance with Act 129, the PPUC issued its proposed guidelines for the filing of utilities’ energy efficiency and peak load reduction plans. On June 18, 2009, the PPUC issued its guidelines related to Smart Meter deployment. On July 1, 2009, Met-Ed, Penelec, and Penn filed Energy Efficiency and Conservation Plans with the PPUC in accordance with Act 129.

Legislation addressing rate mitigation and the expiration of rate caps was not enacted in 2008; however, several bills addressing these issues have been introduced in the current legislative session, which began in January 2009. The final form and impact of such legislation is uncertain.

On February 20, 2009, Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The companies’ plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposes a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. Met-Ed and Penelec have requested PPUC approval of their plan by November 2009.

On February 26, 2009, the PPUC approved a Voluntary Prepayment Plan requested by Met-Ed and Penelec that provides an opportunity for residential and small commercial customers to prepay an amount on their monthly electric bills during 2009 and 2010. Customer prepayments earn interest at 7.5% and will be used to reduce electricity charges in 2011 and 2012.

On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance filing to the PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the residential class with a corresponding increase in the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $51 million), overall rates would remain unchanged. On July 30, 2009, the PPUC entered an order approving the 5-year NUG Statement, approving the reduction of the CTC, and directing Met-Ed and Penelec to file a tariff supplement implementing this change. On July 31, 2009, Met-Ed and Penelec filed tariff supplements decreasing the CTC rate in compliance with the July 30, 2009 order, and increasing the generation rate in compliance with the companies’ Restructuring Orders of 1998. Met-Ed and Penelec are awaiting PPUC action on the July 31, 2009 filings.

(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, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of June 30, 2009, the accumulated deferred cost balance totaled approximately $149 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 DPA 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 March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009. This matter is currently pending before the NJBPU.

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.

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The EMP was issued on October 22, 2008, establishing 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 30% of the state’s electricity needs with renewable energy by 2020;

·   examine smart grid technology and develop additional cogeneration and other generation resources consistent with the state’s greenhouse gas targets; and

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

On January 28, 2009, the NJBPU adopted an order establishing the general process and contents of specific EMP plans that must be filed by December 31, 2009 by New Jersey electric and gas utilities in order to achieve the goals of the EMP. At this time, FirstEnergy cannot determine the impact, if any, the EMP may have on its operations or those of JCP&L.

In support of the New Jersey Governor's Economic Assistance and Recovery Plan, JCP&L announced a proposal to spend approximately $98 million on infrastructure and energy efficiency projects in 2009.  Under the proposal, an estimated $40 million would be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations.  Approximately $34 million would be spent implementing new demand response programs as well as expanding on existing programs.  Another $11 million would be spent on energy efficiency, specifically replacing transformers and capacitor control systems and installing new LED street lights. The remaining $13 million would be spent on energy efficiency programs that would complement those currently being offered. Implementation of the projects is dependent upon resolution of regulatory issues including recovery of the costs associated with the proposal.

(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 is pending before the FERC, and 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. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements.

PJM Transmission Rate

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. AEP's 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.

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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. 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. Oral arguments were held on April 13, 2009. A decision is expected this summer.

The FERC’s orders on PJM rate design would 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 would 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 to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement subject to the submission of a compliance filing. The compliance filing was submitted on August 29, 2008, and the FERC issued an order accepting the compliance filing on October 15, 2008. On November 14, 2008, PJM submitted revisions to its tariff to incorporate cost responsibility assignments for below 500 kV upgrades included in PJM’s Regional Transmission Expansion Planning process in accordance with the settlement. The FERC conditionally accepted the compliance filing on January 28, 2009. PJM submitted a further compliance filing on March 2, 2009, which was accepted by the FERC on April 10, 2009. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. An initial decision was issued by the Presiding Judge on September 18, 2008. PJM and FERC trial staff each filed a Brief on Exceptions to the initial decision on October 20, 2008. Briefs Opposing Exceptions were filed on November 10, 2008.

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 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. The effect of this order is to prevent the shift of significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP was denied by the FERC on December 19, 2008. On February 17, 2009, AEP appealed the FERC’s January 31, 2008, and December 19, 2008, orders to the U.S. Court of Appeals for the Seventh Circuit. FESC, on behalf of its affiliated operating utility companies, filed a motion to intervene on March 10, 2009.

Changes ordered for PJM Reliability Pricing Model (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. On September 19, 2008, the FERC denied the RPM Buyers’ complaint. The FERC also ordered PJM to file on or before December 15, 2008, a report on potential adjustments to the RPM program as suggested in a Brattle Group report. On December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the RPM program. PJM also requested that the FERC conduct a settlement hearing to address changes to the RPM and suggested that the FERC should rule on the tariff amendments only if settlement could not be reached in January, 2009. The request for settlement hearings was granted. Settlement had not been reached by January 9, 2009 and, accordingly, FirstEnergy and other parties submitted comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief Judge issued an order terminating settlement discussions. On February 9, 2009, PJM and a group of stakeholders submitted an offer of settlement, which used the PJM December 12, 2008 filing as its starting point, and stated that unless otherwise specified, provisions filed by PJM on December 12, 2008, apply.

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On March 26, 2009, the FERC accepted in part, and rejected in part, tariff provisions submitted by PJM, revising certain parts of its RPM. Ordered changes included making incremental improvements to RPM; however, the basic construct of RPM remains intact. On April 3, 2009, PJM filed with the FERC requesting clarification on certain aspects of the March 26, 2009 Order. On April 27, 2009, PJM submitted a compliance filing addressing the changes the FERC ordered in the March 26, 2009 Order; and subsequently, numerous parties filed requests for rehearing of the March 26, 2009 Order. On June 18, 2009, the FERC denied rehearing and request for oral argument of the March 26 Order.

PJM has reconvened the Capacity Market Evolution Committee to address issues not addressed in the February 2009 settlement in preparation for September 1, 2009 and December 1, 2009 compliance filings that will recommend more incremental improvements to its RPM.

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 and FES. This requirement was 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 submitted 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.

On October 20, 2008, the FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a compliance filing modifying the cost of new entry penalty. Second, the FERC conditionally accepted MISO's compliance filing on the qualifications for purchased power agreements to be capacity resources, load forecasting, loss of load expectation, and planning reserve zones. Additional compliance filings were directed on accreditation of load modifying resources and price responsive demand. Finally, the FERC largely denied rehearing of its March 26 order with the exception of issues related to behind the meter resources and certain ministerial matters. On November 19, 2008, MISO made various compliance filings pursuant to these orders. Issuance of orders on rehearing and two of the compliance filings occurred on February 19, 2009. No material changes were made to MISO’s Resource Adequacy program. On April 16, 2009, the FERC issued an additional order on rehearing and compliance, approving MISO’s proposed financial settlement provision for Resource Adequacy. The MISO Resource Adequacy process was implemented as planned on June 1, 2009, the beginning of the MISO planning year. On June 17, 2009, MISO submitted a compliance filing in response to the FERC’s April 16, 2009 order directing it to address, among others, various market monitoring and mitigation issues. On July 8, 2009, various parties submitted comments on and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific aspects of the MISO’s and Independent Market Monitor’s proposals for market monitoring and mitigation and other issues that it believes the FERC should address and clarify.

FES Sales to Affiliates

FES supplied all of the power requirements for the Ohio Companies pursuant to a Power Supply Agreement that ended on December 31, 2008. On January 2, 2009, FES signed an agreement to provide 75% of the Ohio Companies’ power requirements for the period January 5, 2009 through March 31, 2009. Subsequently, FES signed an agreement to provide 100% of the Ohio Companies’ power requirements for the period April 1, 2009 through May 31, 2009. On March 4, 2009, the PUCO issued an order approving these two affiliate sales agreements. FERC authorization for these affiliate sales was by means of a December 23, 2008 waiver of restrictions on affiliate sales without prior approval of the FERC.

On May 13-14, 2009, the Ohio Companies held an auction to secure generation supply for their PLR obligation. The results of the auction were accepted by the PUCO on May 14, 2009. Twelve bidders qualified to participate in the auction with nine successful bidders each securing a portion of the Ohio Companies' total supply needs. FES was the successful bidder for 51 tranches, and subsequently purchased 11 additional tranches from other bidders. The auction resulted in an overall weighted average wholesale price of 6.15 cents per KWH for generation and transmission. The new prices for PLR service went into effect with usage beginning June 1, 2009, and continuing through May 31, 2011.

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On October 31, 2008, FES executed a Third Restated Partial Requirements Agreement with Met-Ed, Penelec, and Waverly effective November 1, 2008. The Third Restated Partial Requirements Agreement limits the amount of capacity and energy required to be supplied by FES in 2009 and 2010 to approximately two-thirds of those affiliates’ power supply requirements. Met-Ed, Penelec, and Waverly have committed resources in place for the balance of their expected power supply during 2009 and 2010. Under the Third Restated Partial Requirements Agreement, Met-Ed, Penelec, and Waverly are responsible for obtaining additional power supply requirements created by the default or failure of supply of their committed resources. Prices for the power provided by FES were not changed in the Third Restated Partial Requirements Agreement.

10. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

FSP FAS 132 (R)-1 – “Employers’ Disclosures about Postretirement Benefit Plan Assets”

In December 2008, the FASB issued Staff Position FAS 132(R)-1, which provides guidance on an employer’s disclosures about assets of a defined benefit pension or other postretirement plan. Requirements of this FSP include disclosures about investment policies and strategies, categories of plan assets, fair value measurements of plan assets, and significant categories of risk. This FSP is effective for fiscal years ending after December 15, 2009. FirstEnergy will expand its disclosures related to postretirement benefit plan assets as a result of this FSP.

SFAS 166 – “Accounting for Transfers of Financial Assets – an amendment of FASB Statement No. 140”

In June 2009, the FASB issued SFAS 166, which amends the derecognition guidance in SFAS 140 and eliminates the concept of a qualifying special-purpose entity (QSPE). It removes the exception from applying FIN 46R to QSPEs and requires an evaluation of all existing QSPEs to determine whether they must be consolidated in accordance with SFAS 167. This Statement is effective for financial asset transfers that occur in fiscal years beginning after November 15, 2009. FirstEnergy does not expect this Standard to have a material effect upon its financial statements.

SFAS 167 – “Amendments to FASB Interpretation No. 46(R)”

In June 2009, the FASB issued SFAS 167, which amends the consolidation guidance applied to VIEs. This Statement replaces the quantitative approach previously required to determine which entity has a controlling financial interest in a VIE with a qualitative approach. Under the new approach, the primary beneficiary of a VIE is the entity that has both (a) the power to direct the activities of the VIE that most significantly impact the entity’s economic performance, and (b) the obligation to absorb losses of the entity, or the right to receive benefits from the entity, that could be significant to the VIE. SFAS 167 also requires ongoing reassessments of whether an entity is the primary beneficiary of a VIE and enhanced disclosures about an entity’s involvement in VIEs. This Statement is effective for fiscal years beginning after November 15, 2009. FirstEnergy is currently evaluating the impact of adopting this Standard on its financial statements.

SFAS 168 – “The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162”

In June 2009, the FASB issued SFAS 168, which recognizes the FASB Accounting Standards CodificationTM (Codification) as the source of authoritative GAAP. It also recognizes that rules and interpretative releases of the SEC under federal securities laws are sources of authoritative GAAP for SEC registrants. The Codification supersedes all non-SEC accounting and reporting standards. This Statement is effective for financial statements issued for interim and annual periods ending after September 15, 2009. This Statement will change how FirstEnergy references GAAP in its financial statement disclosures.

136

11. SEGMENT INFORMATION

FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio transitional generation services. The assets and revenues for all other business operations are below the quantifiable threshold for operating segments for separate disclosure as "reportable operating segments." FES and the Utilities do not have separate 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 Met-Ed's and Penelec's 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 affiliated and 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 sales to its affiliates in Ohio and Pennsylvania.

The Ohio transitional generation services segment represents the 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 third parties and the competitive energy services segment through a CBP, 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 primarily of accounts receivable for generation revenues from retail customers.

137

Segment Financial Information
						Ohio
	Energy		Competitive			Transitional
	Delivery		Energy			Generation						Reconciling
Three Months Ended	Services		Services			Services			Other			Adjustments			Consolidated
	(In millions)
June 30, 2009
External revenues	$	1,924	$	504		$	868		$	5		$	(30	)	$	3,271
Internal revenues		-		839			-			-			(839	)		-
Total revenues		1,924		1,343			868			5			(869	)		3,271
Depreciation and amortization		294		68			4			3			4			373
Investment income		35		6			-			-		��	(14	)		27
Net interest charges		113		18			-			2			40			173
Income taxes		89		185			14			(20	)		(20	)		248
Net income		133		276			21			18			(40	)		408
Total assets		22,849		10,144			366			684			263			34,306
Total goodwill		5,551		24			-			-			-			5,575
Property additions		178		248			-			70			(7	)		489
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
Six Months Ended
June 30, 2009
External revenues	$	4,033	$	839		$	1,780		$	12		$	(59	)	$	6,605
Internal revenues		-		1,732			-			-			(1,732	)		-
Total revenues		4,033		2,571			1,780			12			(1,791	)		6,605
Depreciation and amortization		766		132			(41	)		4			7			868
Investment income		64		(23	)		1			-			(26	)		16
Net interest charges		223		36			-			3			77			339
Income taxes		61		288			30			(37	)		(40	)		302
Net income		91		431			45			35			(79	)		523
Total assets		22,849		10,144			366			684			263			34,306
Total goodwill		5,551		24			-			-			-			5,575
Property additions		343		669			-			119			12			1,143
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			43			48			(76	)		540
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

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.

138

12.  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 fully, 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 as a financing for FGCO.

The condensed consolidating statements of income for the three-month and six-month periods ended June 30, 2009 and 2008, consolidating balance sheets as of June 30, 2009 and December 31, 2008 and consolidating statements of cash flows for the six months ended June 30, 2009 and 2008 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 the entries required to reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.

139

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
For the Three Months Ended June 30, 2009	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
REVENUES	$	1,067,987		$	703,110		$	389,695		$	(819,640	)	$	1,341,152
EXPENSES:
Fuel		5,027			238,832			26,450			-			270,309
Purchased power from non-affiliates		185,613			-			-			-			185,613
Purchased power from affiliates		814,622			5,018			51,249			(819,640	)		51,249
Other operating expenses		35,771			99,145			131,159			12,189			278,264
Provision for depreciation		1,017			30,191			35,654			(1,314	)		65,548
General taxes		3,769			11,332			6,184			-			21,285
Total expenses		1,045,819			384,518			250,696			(808,765	)		872,268
OPERATING INCOME		22,168			318,592			138,999			(10,875	)		468,884
OTHER INCOME (EXPENSE):
Miscellaneous income, including net income
from equity investees		288,794			951			6,030			(282,510	)		13,265
Interest expense - affiliates		(34	)		(1,623	)		(1,658	)		-			(3,315	)
Interest expense - other		(2,900	)		(24,967	)		(14,677	)		16,273			(26,271	)
Capitalized interest		46			11,126			2,856			-			14,028
Total other income (expense)		285,906			(14,513	)		(7,449	)		(266,237	)		(2,293	)
INCOME BEFORE INCOME TAXES		308,074			304,079			131,550			(277,112	)		466,591
INCOME TAXES		10,672			108,114			48,163			2,240			169,189
NET INCOME	$	297,402		$	195,965		$	83,387		$	(279,352	)	$	297,402

140

FIRSTENERGY SOLUTIONS CORP.
CONDENSED 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

141

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
For the Six Months Ended June 30, 2009	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
REVENUES	$	2,269,882		$	1,249,036		$	785,323		$	(1,736,983	)	$	2,567,258
EXPENSES:
Fuel		7,122			513,679			55,666			-			576,467
Purchased power from non-affiliates		345,955			-			-			-			345,955
Purchased power from affiliates		1,729,883			7,100			114,456			(1,736,983	)		114,456
Other operating expenses		74,038			203,588			283,615			24,379			585,620
Provision for depreciation		2,036			60,211			67,303			(2,629	)		126,921
General taxes		8,475			23,958			12,228			-			44,661
Total expenses		2,167,509			808,536			533,268			(1,715,233	)		1,794,080
OPERATING INCOME		102,373			440,500			252,055			(21,750	)		773,178
OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		409,307			904			(23,607	)		(399,702	)		(13,098	)
Interest expense - affiliates		(68	)		(3,381	)		(2,845	)		-			(6,294	)
Interest expense - other		(5,420	)		(46,025	)		(29,845	)		32,492			(48,798	)
Capitalized interest		97			18,876			5,133			-			24,106
Total other income (expense)		403,916			(29,626	)		(51,164	)		(367,210	)		(44,084	)
INCOME BEFORE INCOME TAXES		506,289			410,874			200,891			(388,960	)		729,094
INCOME TAXES		38,206			147,256			71,092			4,457			261,011
NET INCOME	$	468,083		$	263,618		$	129,799		$	(393,417	)	$	468,083

142

FIRSTENERGY SOLUTIONS CORP.
CONDENSED 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

143

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
As of June 30, 2009	FES		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	120,000	$	34	$	-	$	-		$	120,034
Receivables-
Customers		75,753		-		-		-			75,753
Associated companies		222,514		152,509		105,559		(265,220	)		215,362
Other		3,477		10,979		4,853		-			19,309
Notes receivable from associated companies		369,068		1,277		-		-			370,345
Materials and supplies, at average cost		10,370		329,132		210,710		-			550,212
Prepayments and other		76,784		18,875		2,722		-			98,381
		877,966		512,806		323,844		(265,220	)		1,449,396
PROPERTY, PLANT AND EQUIPMENT:
In service		89,296		5,501,668		5,025,760		(389,939	)		10,226,785
Less - Accumulated provision for depreciation		11,838		2,760,063		1,801,089		(172,808	)		4,400,182
		77,458		2,741,605		3,224,671		(217,131	)		5,826,603
Construction work in progress		3,832		1,735,258		280,658		-			2,019,748
		81,290		4,476,863		3,505,329		(217,131	)		7,846,351
INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,040,410		-			1,040,410
Investment in associated companies		4,059,946		-		-		(4,059,946	)		-
Other		1,517		27,493		202		-			29,212
		4,061,463		27,493		1,040,612		(4,059,946	)		1,069,622
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes		7,250		424,814		-		(280,607	)		151,457
Lease assignment receivable from associated companies		-		71,356		-		-			71,356
Goodwill		24,248		-		-		-			24,248
Property taxes		-		27,494		22,610		-			50,104
Unamortized sale and leaseback costs		-		17,533		-		56,748			74,281
Other		40,108		67,288		8,782		(53,873	)		62,305
		71,606		608,485		31,392		(277,732	)		433,751
	$	5,092,325	$	5,625,647	$	4,901,177	$	(4,820,029	)	$	10,799,120
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	717	$	698,493	$	951,240	$	(18,186	)	$	1,632,264
Short-term borrowings-
Associated companies		-		174,769		135,063		-			309,832
Other		1,100,000		-		-		-			1,100,000
Accounts payable-
Associated companies		288,626		184,839		131,438		(237,508	)		367,395
Other		55,039		113,446		-		-			168,485
Accrued taxes		56,092		33,217		22,274		(42,824	)		68,759
Other		38,397		97,054		10,824		34,715			180,990
		1,538,871		1,301,818		1,250,839		(263,803	)		3,827,725
CAPITALIZATION:
Common stockholder's equity		3,494,790		2,136,867		1,905,900		(4,042,767	)		3,494,790
Long-term debt and other long-term obligations		21,620		1,688,863		533,990		(1,278,796	)		965,677
		3,516,410		3,825,730		2,439,890		(5,321,563	)		4,460,467
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		1,009,727			1,009,727
Accumulated deferred income taxes		-		-		244,390		(244,390	)		-
Accumulated deferred investment tax credits		-		37,899		22,663		-			60,562
Asset retirement obligations		-		24,627		866,878		-			891,505
Retirement benefits		18,841		113,041		-		-			131,882
Property taxes		-		27,494		22,610		-			50,104
Lease market valuation liability		-		284,952		-		-			284,952
Other		18,203		10,086		53,907		-			82,196
		37,044		498,099		1,210,448		765,337			2,510,928
	$	5,092,325	$	5,625,647	$	4,901,177	$	(4,820,029	)	$	10,799,120

144

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
As of December 31, 2008	FES		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	-	$	39	$	-	$	-		$	39
Receivables-
Customers		86,123		-		-		-			86,123
Associated companies		363,226		225,622		113,067		(323,815	)		378,100
Other		991		11,379		12,256		-			24,626
Notes receivable from associated companies		107,229		21,946		-		-			129,175
Materials and supplies, at average cost		5,750		303,474		212,537		-			521,761
Prepayments and other		76,773		35,102		660		-			112,535
		640,092		597,562		338,520		(323,815	)		1,252,359
PROPERTY, PLANT AND EQUIPMENT:
In service		134,905		5,420,789		4,705,735		(389,525	)		9,871,904
Less - Accumulated provision for depreciation		13,090		2,702,110		1,709,286		(169,765	)		4,254,721
		121,815		2,718,679		2,996,449		(219,760	)		5,617,183
Construction work in progress		4,470		1,441,403		301,562		-			1,747,435
		126,285		4,160,082		3,298,011		(219,760	)		7,364,618
INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,033,717		-			1,033,717
Long-term notes receivable from associated companies		-		-		62,900		-			62,900
Investment in associated companies		3,596,152		-		-		(3,596,152	)		-
Other		1,913		59,476		202		-			61,591
		3,598,065		59,476		1,096,819		(3,596,152	)		1,158,208
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits		24,703		476,611		-		(233,552	)		267,762
Lease assignment receivable from associated companies		-		71,356		-		-			71,356
Goodwill		24,248		-		-		-			24,248
Property taxes		-		27,494		22,610		-			50,104
Unamortized sale and leaseback costs		-		20,286		-		49,646			69,932
Other		59,642		59,674		21,743		(44,625	)		96,434
		108,593		655,421		44,353		(228,531	)		579,836
	$	4,473,035	$	5,472,541	$	4,777,703	$	(4,368,258	)	$	10,355,021
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	5,377	$	925,234	$	1,111,183	$	(16,896	)	$	2,024,898
Short-term borrowings-
Associated companies		1,119		257,357		6,347		-			264,823
Other		1,000,000		-		-		-			1,000,000
Accounts payable-
Associated companies		314,887		221,266		250,318		(314,133	)		472,338
Other		35,367		119,226		-		-			154,593
Accrued taxes		8,272		60,385		30,790		(19,681	)		79,766
Other		61,034		136,867		13,685		36,853			248,439
		1,426,056		1,720,335		1,412,323		(313,857	)		4,244,857
CAPITALIZATION:
Common stockholder's equity		2,944,423		1,832,678		1,752,580		(3,585,258	)		2,944,423
Long-term debt and other long-term obligations		61,508		1,328,921		469,839		(1,288,820	)		571,448
		3,005,931		3,161,599		2,222,419		(4,874,078	)		3,515,871
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		1,026,584			1,026,584
Accumulated deferred income taxes		-		-		206,907		(206,907	)		-
Accumulated deferred investment tax credits		-		39,439		23,289		-			62,728
Asset retirement obligations		-		24,134		838,951		-			863,085
Retirement benefits		22,558		171,619		-		-			194,177
Property taxes		-		27,494		22,610		-			50,104
Lease market valuation liability		-		307,705		-		-			307,705
Other		18,490		20,216		51,204		-			89,910
		41,048		590,607		1,142,961		819,677			2,594,293
	$	4,473,035	$	5,472,541	$	4,777,703	$	(4,368,258	)	$	10,355,021

145

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
For the Six Months Ended June 30, 2009	FES			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
NET CASH PROVIDED FROM OPERATING ACTIVITIES	$	285,284		$	314,041		$	221,625		$	(8,734	)	$	812,216
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			347,710			333,965			-			681,675
Short-term borrowings, net		98,880			-			128,716			(82,587	)		145,009
Redemptions and Repayments-
Long-term debt		(1,696	)		(260,372	)		(369,519	)		8,734			(622,853	)
Short-term borrowings, net		-			(82,587	)		-			82,587			-
Net cash provided from financing activities		97,184			4,751			93,162			8,734			203,831
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(694	)		(332,789	)		(301,484	)		-			(634,967	)
Proceeds from asset sales		-			15,771			-			-			15,771
Sales of investment securities held in trusts		-			-			537,078			-			537,078
Purchases of investment securities held in trusts		-			-			(550,730	)		-			(550,730	)
Loan repayments from (loans to) associated companies, net		(261,839	)		20,669			-			-			(241,170	)
Other		65			(22,448	)		349			-			(22,034	)
Net cash used for investing activities		(262,468	)		(318,797	)		(314,787	)		-			(896,052	)
Net change in cash and cash equivalents		120,000			(5	)		-			-			119,995
Cash and cash equivalents at beginning of period		-			39			-			-			39
Cash and cash equivalents at end of period	$	120,000		$	34		$	-		$	-		$	120,034

146

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

147

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 effectiveness of the registrant's disclosure controls and procedures as of the end of the period covered by this report. 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 were effective as of the end of the period covered by this report.

(b)      CHANGES IN INTERNAL CONTROLS

During the quarter ended June 30, 2009, 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 the effectiveness of such registrant's disclosure controls and procedures as of the end of the period covered by this report. 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 were effective as of the end of the period covered by this report.

(b)      CHANGES IN INTERNAL CONTROLS

During the quarter ended June 30, 2009, 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.

148

PART II. OTHER INFORMATION

ITEM 1.            LEGAL PROCEEDINGS

Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 8 and 9 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, 2008, and Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, include a detailed discussion of its risk factors. For the quarter ended June 30, 2009, there have been no material changes to these risk factors.

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

(c)           FirstEnergy

The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock during the second quarter of 2009.

	Period
	April	May	June	Second Quarter
Total Number of Shares Purchased (a)	25,666	26,682	436,452	488,800
Average Price Paid per Share	$39.08	$39.86	$38.68	$38.76
Total Number of Shares Purchased
As Part of Publicly Announced Plans
or Programs	-	-	-	-
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.

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

(a) The annual meeting of FirstEnergy shareholders was held on May 19, 2009.

(b) At this meeting, the following persons (comprising all members of the Board) were elected to FirstEnergy's Board of Directors until the Annual Meeting of Shareholders in 2010 and until their successors have been elected:

	Number of Votes
	For		Withheld
Paul T. Addison		115,453,478		107,532,193
Anthony J. Alexander		115,319,952		107,665,719
Michael J. Anderson		115,182,823		107,802,848
Dr. Carol A. Cartwright		107,462,102		115,523,569
William T. Cottle		108,415,632		114,570,039
Robert B. Heisler, Jr.		114,997,860		107,987,811
Ernest J. Novak, Jr.		115,243,864		107,741,807
Catherine A. Rein		114,687,786		108,297,885
George M. Smart		107,568,271		115,417,400
Wes M. Taylor		115,400,913		107,584,758
Jesse T. Williams, Sr.		107,935,870		115,049,801

149

(c) (i) At this meeting, the appointment of PricewaterhouseCoopers LLP, an independent registered public accounting firm, as auditor for the 2009 fiscal year was ratified:

Number of Votes
For	Against	Abstentions
219,754,593	2,100,019	1,131,567

(ii) 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
155,741,944	36,909,437	2,395,715	27,939,083

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 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
110,529,850	82,017,229	2,499,618	27,939,482

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

(iv)   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, excluding abstentions and broker non-votes, at any annual meeting was not approved (approval required a favorable vote of a majority of the votes cast):

Number of Votes
			Broker
For	Against	Abstentions	Non-Votes
88,329,182	103,545,248	3,172,666	27,939,083

(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
128,558,349	64,162,961	2,325,387	27,939,482

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

150

ITEM 6.   EXHIBITS

Exhibit Number
FirstEnergy
	10.1		Form of Written Consent for Named Executive Officers dated June 1, 2009
	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
	101*		The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended June 30, 2009, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.
FES
		4.1	Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 1, 2009, by and between FirstEnergy Nuclear Generation Corp. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 4.1)
		4.2	First Supplemental Indenture, dated as of June 15, 2009, to Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 1, 2009, by and between FirstEnergy Nuclear Generation Corp. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 4.2)
		4.2(a)	Form of First Mortgage Bonds, Guarantee Series A of 2009 due 2033 (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(a))
		4.2(b)	Form of First Mortgage Bonds, Guarantee Series B of 2009 due 2011 (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(b))
		4.2(c)	Form of First Mortgage Bonds, Collateral Series A of 2009 due 2010 (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(c))
		4.2(d)	Form of First Mortgage Bonds, Collateral Series B of 2009 due 2010 (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(d))
		4.2(e)	Form of First Mortgage Bonds, Collateral Series C of 2009 due 2010 (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(e))
		4.2(f)	Form of First Mortgage Bonds, Collateral Series D of 2009 due 2010 (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(f))
		4.2(g)	Form of First Mortgage Bonds, Collateral Series E of 2009 due 2010 (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(g))
		4.2(h)	Form of First Mortgage Bonds, Collateral Series F of 2009 due 2011 (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(h))
		4.2(i)	Form of First Mortgage Bonds, Collateral Series G of 2009 due 2011 (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(i))
		4.3	Second Supplemental Indenture, dated as of June 30, 2009, to Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 1, 2009, by and between FirstEnergy Nuclear Generation Corp. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No. 333-145140-01), Exhibit 4.1)
		4.3(a)	Form of First Mortgage Bonds, Guarantee Series C of 2009 due 2033 (incorporated by reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No. 333-145140-01), Exhibit 4.1(a))

151

4.3(b)	Form of First Mortgage Bonds, Guarantee Series D of 2009 due 2033 (incorporated by reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No. 333-145140-01), Exhibit 4.1(b))
4.3(c)	Form of First Mortgage Bonds, Guarantee Series E of 2009 due 2033 (incorporated by reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No. 333-145140-01), Exhibit 4.1(c))
4.3(d)	Form of First Mortgage Bonds, Collateral Series H of 2009 due 2011 (incorporated by reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No. 333-145140-01), Exhibit 4.1(d))
4.3(e)	Form of First Mortgage Bonds, Collateral Series I of 2009 due 2011 (incorporated by reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No. 333-145140-01), Exhibit 4.1(e))
4.3(f)	Form of First Mortgage Bonds, Collateral Series J of 2009 due 2010 (incorporated by reference to FES’ Form 8-K filed on July 6, 2009 (SEC File No. 333-145140-01), Exhibit 4.1(f))
4.4	Fourth Supplemental Indenture, dated as of June 1, 2009, to Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 19, 2008, by and between FirstEnergy Generation Corp. and The Bank of New York Mellon Trust Company, N.A. (formerly known as The Bank of New York Trust Company, N.A.), as trustee (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01, Exhibit 4.3(a))
4.4(a)	Form of First Mortgage Bonds, Guarantee Series C of 2009 due 2018 (incorporated by reference to FES Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01, Exhibit 4.3(a))
4.4(b)	Form of First Mortgage Bonds, Guarantee Series D of 2009 due 2029 (incorporated by reference to FES Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01, Exhibit 4.3(b))
4.4(c)	Form of First Mortgage Bonds, Guarantee Series E of 2009 due 2029 (incorporated by reference to FES Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01, Exhibit 4.3(c))
4.4(d)	Form of First Mortgage Bonds, Collateral Series B of 2009 due 2011 (incorporated by reference to FES Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01, Exhibit 4.3(d))
4.4(e)	Form of First Mortgage Bonds, Collateral Series C of 2009 due 2011 (incorporated by reference to FES Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01, Exhibit 4.3(e))
4.5	Fifth Supplemental Indenture, dated as of June 30, 2009, to Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 19, 2008, by and between FirstEnergy Generation Corp. and The Bank of New York Mellon Trust Company, N.A. (formerly known as The Bank of New York Trust Company, N.A.), as trustee (incorporated by reference to FES’ Form 8-K (SEC File No. 333-145140-01) filed on July 6, 2009, Exhibit 4.2)
4.5(a)	Form of First Mortgage Bonds, Guarantee Series F of 2009 due 2047 (incorporated by reference to FES’ Form 8-K  filed on July 6, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(a))
4.5(b)	Form of First Mortgage Bonds, Guarantee Series G of 2009 due 2018 (incorporated by reference to FES’ Form 8-K filed on July 6, 2009  (SEC File No. 333-145140-01), Exhibit 4.2(b))
4.5(c)	Form of First Mortgage Bonds, Guarantee Series H of 2009 due 2018 (incorporated by reference to FES’ Form 8-K  filed on July 6, 2009 (SEC File No. 333-145140-01), Exhibit 4.2(c))
10.2	Master SSO Supply Agreement, entered into May 18, 2009, by and between The Cleveland Electric Illuminating Company, the Toledo Edison Company and Ohio Edison Company and FirstEnergy Solutions Corp.
(A) 10.2	Form of Amendment No. 2 to Letter of Credit and Reimbursement Agreement, dated as of June 12, 2009, by and among FirstEnergy Nuclear Generation Corp., FirstEnergy Corp. and FirstEnergy Solutions Corp., as guarantors, the banks party thereto, and Barclays Bank PLC, as fronting Bank and administrative agent, to Letter of Credit and Reimbursement Agreement dated as of December 16, 2005 (incorporated by reference to FES’ Form 8-K filed on June 19, 2009  (SEC File No. 333-145140-01), Exhibit 10.1)

152

	(B) 10.3	Form of Amendment No. 2 to Letter of Credit and Reimbursement Agreement, dated as of June 12, 2009, by and among FirstEnergy Generation Corp., FirstEnergy Corp. and FirstEnergy Solutions Corp., as guarantors, the banks party thereto, Barclays Bank PLC, as fronting Bank and administrative agent and KeyBank National Association, as syndication agent, to Letter of Credit and Reimbursement Agreement dated as of April 3, 2006 (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 10.2)
	10.4	Surplus Margin Guaranty, dated as of June 16, 2009, made by FirstEnergy Nuclear Generation Corp. in favor of The Cleveland Electric Illuminating Company, The Toledo Edison Company and Ohio Edison Company (incorporated by reference to FES’ Form 8-K filed on June 19, 2009 (SEC File No. 333-145140-01), Exhibit 10.3)
	12	Fixed charge ratios
	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
	10.2	Master SSO Supply Agreement, entered into May 18, 2009, by and between The Cleveland Electric Illuminating Company, the Toledo Edison Company and Ohio Edison Company and FirstEnergy Solutions Corp.
	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
	10.2	Master SSO Supply Agreement, entered into May 18, 2009, by and between The Cleveland Electric Illuminating Company, the Toledo Edison Company and Ohio Edison Company and FirstEnergy Solutions Corp.
	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
TE
	10.2	Master SSO Supply Agreement, entered into May 18, 2009, by and between The Cleveland Electric Illuminating Company, the Toledo Edison Company and Ohio Edison Company and FirstEnergy Solutions Corp.
	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
JCP&L
	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
Met-Ed
	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

153

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
	(A)	Four substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to four other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority, the Ohio Air Quality Authority and Beaver County Industrial Development Authority, Pennsylvania, relating to pollution control notes of FirstEnergy Nuclear Generation Corp.
	(B)	Three substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to three other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority and the Beaver County Industrial Development Authority relating to pollution control notes of FirstEnergy Generation Corp. and FirstEnergy Nuclear Generation Corp.

* Users of this data are advised pursuant to Rule 401 of Regulation S-T that the financial information contained in the XBRL-Related Documents is unaudited and, as a result, investors should not rely on the XBRL-Related Documents in making investment decisions.  Furthermore, users of this data are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.

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

Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, 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.

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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 3, 2009

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)

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