Commission	Registrant; State of Incorporation;	I.R.S. Employer
File Number	Address; and Telephone Number	Identification No.
333-21011	FIRSTENERGY CORP.	34-1843785
	(An Ohio Corporation)
	76 South Main Street
	Akron, OH  44308
	Telephone (800)736-3402
333-145140-01	FIRSTENERGY SOLUTIONS CORP.	31-1560186
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402
1-2578	OHIO EDISON COMPANY	34-0437786
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH  44308
	Telephone (800)736-3402
1-2323	THE CLEVELAND ELECTRIC ILLUMINATING COMPANY	34-0150020
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH  44308
	Telephone (800)736-3402
1-3583	THE TOLEDO EDISON COMPANY	34-4375005
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH  44308
	Telephone (800)736-3402
1-3141	JERSEY CENTRAL POWER & LIGHT COMPANY	21-0485010
	(A New Jersey Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH  44308
	Telephone (800)736-3402
1-446	METROPOLITAN EDISON COMPANY	23-0870160
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH  44308
	Telephone (800)736-3402
1-3522	PENNSYLVANIA ELECTRIC COMPANY	25-0718085
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH  44308
	Telephone (800)736-3402

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

				Name of Each Exchange
Registrant		Title of Each Class		on Which Registered
FirstEnergy Corp.		Common Stock, $0.10 par value		New York Stock Exchange

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

Registrant		Title of Each Class
Ohio Edison Company		Common Stock, no par value per share
The Cleveland Electric Illuminating Company		Common Stock, no par value per share
The Toledo Edison Company		Common Stock, $5.00 par value per share
Jersey Central Power & Light Company		Common Stock, $10.00 par value per share
Metropolitan Edison Company		Common Stock, no par value per share
Pennsylvania Electric Company		Common Stock, $20.00 par value per share

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

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

		OUTSTANDING
CLASS		AS OF FEBRUARY 24, 2009
FirstEnergy Corp., $.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

		PART OF FORM 10-K INTO WHICH
DOCUMENT		DOCUMENT IS INCORPORATED
FirstEnergy Corp. Annual Report to Stockholders for
the fiscal year ended December 31, 2008		Part II
Proxy Statement for 2009 Annual Meeting of Stockholders
to be held May 19, 2009		Part III

GLOSSARY OF TERMS

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

ATSI	American Transmission Systems, Inc., owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
Centerior	Centerior Energy Corporation, former parent of CEI and TE, which merged with OE to form     FirstEnergy on November 8, 1997
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 c ompany and issuer of transition     bonds
Met-Ed	Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
MYR	MYR Group, Inc., a utility infrastructure construction service company
NGC	FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities
OE	Ohio Edison Company, an Ohio electric utility operating subsidiary
Ohio Companies	CEI, OE and TE
Penelec	Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Penn	Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
Pennsylvania Companies	Met-Ed, Penelec and Penn
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, formerly known as Bull Mountain
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:
ACO	Administrative Consent Order
AEP	American Electric Power Company, Inc.
ALJ	Administrative Law Judge
AMP-Ohio	American Municipal Power - Ohio
AQC	Air Quality Control
BGS	Basic Generation Service
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CAVR	Clean Air Visibility Rule
CBP	Competitive Bid Process
CO 2	Carbon Dioxide
CTC	Competitive Transition Charge
DFI	Demand for Information
DOE	United States Department of Energy
DOJ	United States Department of Justice
DRA	Division of Ratepayer Advocate
ECAR	East Central Area Reliability Coordination Agreement
EIS	Energy Independence Strategy
EMP	Energy Master Plan
EPA	United States Environmental Protection Agency
EPACT	Energy Policy Act of 2005
EPRI	Electric Power Research Institute
ERO	Electric Reliability Organization
ESP	Electric Security Plan
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission

 

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GLOSSARY OF TERMS Cont’d.

FMB	First Mortgage Bond
FPA	Federal Power Act
GHG	Greenhouse Gases
IRS	Internal Revenue Service
ISO	Independent System Operator
kV	Kilovolts
KWH	Kilowatt-hours
LED	Light-emitting Diode
MEW	Mission Energy Westside, Inc.
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service, Inc.
MRO	Market Rate Offer
MW	Megawatts
MWH	Megawatt-hour
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NJBPU	New Jersey Board of Public Utilities
NOV	Notice of Violation
NO X	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
NSR	New Source Review
NUG	Non-Utility Generation
NUGC	Non-Utility Generation Charge
OCA	Office of Consumer Advocate
OSBA	Office of Small Business Advocate
OVEC	Ohio Valley Electric Corporation
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
PRP	Potentially Responsible Party
PSA	Power Supply Agreement
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act of 1935
RCP	Rate Certainty Plan
RECB	Regional Expansion Criteria and Benefits
RFP	Request for Proposal
RSP	Rate Stabilization Plan
RTC	Regulatory Transition Charge
RTO	Regional Transmission Organization
S&P	Standard & Poor’s Ratings Service
SBC	Societal Benefits Charge
SEC	U.S. Securities and Exchange Commission
SECA	Seams Elimination Cost Adjustment
SFAS	Statement of Financial Accounting Standards
SFAS 71	SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
SFAS 101	SFAS No. 101, "Accounting for Discontinuation of Application of SFAS 71"
SIP	State Implementation Plan(s) Under the Clean Air Act
SNCR	Selective Non-Catalytic Reduction
SO 2	Sulfur Dioxide
TMI-1	Three Mile Island Unit 1
TMI-2	Three Mile Island Unit 2
TSC	Transmission Service Charge

 

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FORM 10-K TABLE OF CONTENTS

	Page
Part I
Item 1.    Business
The Company	1-2
Utility Regulation	2-11
Regulatory Accounting	3
Reliability Initiatives	3-4
PUCO Rate Matters	4-5
PPUC Rate Matters	6-7
NJBPU Rate Matters	7-8
FERC Rate Matters	8-11
Capital Requirements	11-13
Nuclear Operating Licenses	13-14
Nuclear Regulation	14
Nuclear Insurance	14-15
Environmental Matters	15-19
Fuel Supply	19-20
System Demand	20
Supply Plan	20
Regional Reliability	21
Competition	21
Research and Development	21
Executive Officers	22
Employees	23
FirstEnergy Web Site	23
Item 1A.  Risk Factors	23-36
Item 1B.  Unresolved Staff Comments	36
Item 2.     Properties	36-38
Item 3.     Legal Proceedings	38
Item 4.     Submission of Matters to a Vote of Security Holders	38
Part II
Item 5.     Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	38-39
Item 6.     Selected Financial Data	39
Item 7.     Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
Item 7A.  Quantitative and Qualitative Disclosures About Market Risk	39
Item 8.     Financial Statements and Supplementary Data	39
Item 9.     Changes In and Disagreements with Accountants on Accounting and Financial Disclosure	39
Item 9A.  Controls and Procedures	39-40
Item 9A(T).  Controls and Procedures	40
Item 9B.  Other Information	40
Part III
Item 10.   Directors, Executive Officers and Corporate Governance	41
Item 11.   Executive Compensation	41
Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	41
Item 13.   Certain Relationships and Related Transactions, and Director Independence	41
Item 14.   Principal Accounting Fees and Services	41
Part IV
Item 15.   Exhibits, Financial Statement Schedules	42-88

 

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PART I

ITEM 1.   BUSINESS

The Company

FirstEnergy Corp. was organized under the laws of the State of Ohio in 1996. FirstEnergy’s principal business is the holding, directly or indirectly, of all of the outstanding common stock of its eight principal electric utility operating subsidiaries: OE, CEI, TE, Penn, ATSI, JCP&L, Met-Ed and Penelec. FirstEnergy’s consolidated revenues are primarily derived from electric service provided by its utility operating subsidiaries and the revenues of its other principal subsidiary, FES. In addition, FirstEnergy holds all of the outstanding common stock of other direct subsidiaries including: FirstEnergy Properties, Inc., FirstEnergy Ventures Corp., FENOC, FirstEnergy Securities Transfer Company, GPU Diversified Holdings, LLC, GPU Telecom Services, Inc., GPU Nuclear, Inc. and FESC.

FES was organized under the laws of the State of Ohio in 1997.  FES provides energy-related products and services to wholesale and retail customers in the MISO and PJM markets. FES also owns and operates, through its subsidiary, FGCO, FirstEnergy’s fossil and hydroelectric generating facilities and owns, through its subsidiary, NGC, FirstEnergy’s nuclear generating facilities. FENOC, a separate subsidiary of FirstEnergy, organized under the laws of the State of Ohio in 1998, operates and maintains NGC’s nuclear generating facilities. FES purchases the entire output of the generation facilities owned by FGCO and NGC, as well as the output relating to leasehold interests of the Ohio Companies in certain of those facilities that are subject to sale and leaseback arrangements with non-affiliates, pursuant to full output, cost-of-service PSAs.

FirstEnergy’s generating portfolio includes 14,173 MW of diversified capacity (FES – 13,973 MW and JCP&L – 200 MW). Within FES’ portfolio, approximately 7,469 MW, or 53.5%, consists of coal-fired capacity; 3,991 MW, or 28.6%, consists of nuclear capacity; 1,599 MW, or 11.4%, consists of oil and natural gas peaking units; 451 MW, or 3.2%, consists of hydroelectric capacity; and 463 MW, or 3.3%, consists of capacity from FGCO’s current 20.5% entitlement to the generation output owned by the OVEC. FirstEnergy’s nuclear and non-nuclear facilities are operated by FENOC and FGCO, respectively, and, except for portions of certain facilities that are subject to the sale and leaseback arrangements with non-affiliates referred to above for which the corresponding output is available to FES through power sale agreements, are all owned directly by NGC and FGCO, respectively. The FES generating assets are concentrated primarily in Ohio, plus the bordering regions of Pennsylvania and Michigan. All FES units are dedicated to MISO except the Beaver Valley Power Station, which is designated as a PJM resource.

FES, FGCO and NGC compl y with the regulations, orders, policies and practices prescribed by the SEC and the FER C. In addition, NGC and FENOC comply with the regulations, orders, policies and practices prescribed by the NRC.

The Utilities’ combined service areas encompass approximately 36,100 square miles in Ohio, New Jersey and Pennsylvania. The areas they serve have a combined population of approximately 11.3 million.

OE was organized under the laws of the State of Ohio in 1930 and owns property and does business as an electric public utility in that state. OE engages in the distribution and sale of electric energy to communities in a 7,000 square mile area of central and northeastern Ohio. The area it serves has a population of approximately 2.8 million. OE compl ies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PUCO.

OE owns all of Penn’s outstanding common stock. Penn was organized under the laws of the Commonwealth of Pennsylvania in 1930 and owns property and does business as an electric public utility in that state. Penn is also authorized to do business in the State of Ohio (see Item 2 – Properties). Penn furnishes electric service to communities in 1,100 square miles of western Pennsylvania. The area it serves has a population of approximately 0.4 million.   Penn compl ies with the regulations, orders, policies and practices prescribed by the FERC and PPUC.

CEI was organized under the laws of the State of Ohio in 1892 and does business as an electric public utility in that state. CEI engages in the distribution and sale of electric energy in an area of approximately 1,600 square miles in northeastern Ohio. The area it serves has a population of approximately 1.8 million. CEI compl ies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PUCO.

TE was organized under the laws of the State of Ohio in 1901 and does business as an electric public utility in that state. TE engages in the distribution and sale of electric energy in an area of approximately 2,300 square miles in northwestern Ohio. The area it serves has a population of approximately 0.8 million. TE compl ies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PUCO.

 

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ATSI was organized under the laws of the State of Ohio in 1998. ATSI owns transmission assets that were formerly owned by the Ohio Companies and Penn. ATSI owns major, high-voltage transmission facilities, which consist of approximately 5,821 pole miles of transmission lines with nominal voltages of 345 kV, 138 kV and 69 kV. Effective October 1, 2003, ATSI transferred operational control of its transmission facilities to MISO. With its affiliation with MISO, ATSI plans, operates, and maintains its transmission system in accordance with NERC reliability standards, and applicable regulatory agencies to ensure reliable service to customers.

JCP&L was organized under the laws of the State of New Jersey in 1925 and owns property and does business as an electric public utility in that state. JCP&L provides transmission and distribution services in 3,200 square miles of northern, western and east central New Jersey. The area it serves has a population of approximately 2.6 million. JCP&L compl ies with the regulations, orders, policies and practices prescribed by the SEC, FERC and the NJBPU .

Met-Ed was organized under the laws of the Commonwealth of Pennsylvania in 1922 and owns property and does business as an electric public utility in that state. Met-Ed provides transmission and distribution services in 3,300 square miles of eastern and south central Pennsylvania. The area it serves has a population of approximately 1.3 million. Met-Ed compl ies with the regulations, orders, policies and practices prescribed by the SEC, FERC and P P UC.

Penelec was organized under the laws of the Commonwealth of Pennsylvania in 1919 and owns property and does business as an electric public utility in that state. Penelec provides transmission and distribution services in 17,600 square miles of western, northern and south central Pennsylvania. The area it serves has a population of approximately 1.6 million. Penelec, as lessee of the property of its subsidiary, The Waverly Electric Light & Power Company, also serves customers in Waverly, New York and its vicinity. Penelec compl ies with the regulations, orders, policies and practices prescribed by the SEC, FERC and P P UC.

FESC provides legal, financial and other corporate support services to affiliated FirstEnergy companies.

Reference is made to Note 15, Segment Information, of the Notes to Consolidated Financial Statements contained in Item 8 for information regarding FirstEnergy's reportable segments.

Utility Regulation

State Regulation

Each of the Utilities’ retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the state in which each company operates – in Ohio by the PUCO, in New Jersey by the NJBPU and in Pennsylvania by the PPUC.  In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility.

As a competitive retail electric supplier serving retail customers in Ohio, Pennsylvania, Maryland, Michigan, and Illinois, FES is subject to state laws applicable to competitive electric suppliers in those states, including affiliate codes of conduct that apply to FES and its public utility affiliates.  In addition, if FES or any of its subsidiaries were to engage in the construction of significant new generation facilities, they would also be subject to state siting authority.

Federal Regulation

With respect to their wholesale and interstate electric operations and rates, the Utilities, ATSI, FES, FGCO and NGC are subject to regulation by the FERC. Under the FPA, the FERC regulates rates for interstate sales at wholesale, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. The FERC regulations require ATSI, Met-Ed, JCP&L and Penelec to provide open access transmission service at FERC-approved rates, terms and conditions.  Transmission service over ATSI’s facilities is provided by MISO under its open access transmission tariff, and transmission service over Met-Ed’s, JCP&L’s and Penelec’s facilities is provided by PJM under its open access transmission tariff. The FERC also regulates unbundled transmission service to retail customers.

The FERC regulates the sale of power for resale in interstate commerce by granting authority to public utilities to sell wholesale power at market-based rates upon a showing that the seller cannot exert market power in generation or transmission. FES, FGCO and NGC have been authorized by the FERC to sell wholesale power in interstate commerce and have a market-based tariff on file with the FERC. By virtue of this tariff and authority to sell wholesale power, each company is regulated as a public utility under the FPA.  However, consistent with its historical practice, the FERC has granted FES, FGCO and NGC a waiver from most of the reporting, record-keeping and accounting requirements that typically apply to traditional public utilities.  Along with market-based rate authority, the FERC also granted FES, FGCO and NGC blanket authority to issue securities and assume liabilities under Section 204 of the FPA. As a condition to selling electricity on a wholesale basis at market-based rates, FES, FGCO and NGC, like all other entities granted market-based rate authority, must file electronic quarterly reports with the FERC, listing its sales transactions for the prior quarter.

 

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The nuclear generating facilities owned and leased by NGC are subject to extensive regulation by the NRC.  The NRC subjects nuclear generating stations to continuing review and regulation covering, among other things, operations, maintenance, emergency planning, security and environmental and radiological aspects of those stations. The NRC may modify, suspend or revoke operating licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of the licenses. FENOC is the licensee for these plants and has direct compliance responsibility for NRC matters. FES controls the economic dispatch of NGC’s plants.  See “Nuclear Regulation” below.

Regulatory Accounting

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

FirstEnergy accounts for the effects of regulation through the application of SFAS 71 to its operating utilities since their rates:

·

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

·

are cost-based; and

·

can be charged to and collected from customers.

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

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.

Reliability Initiatives

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

 

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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 Midwest ISO 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 a final report is expected in early 2009. FirstEnergy does not expect any material adverse financial impact as a result of these audits.

PUCO Rate Matters

On January 4, 2006, the PUCO issued an order authorizing the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a twenty-five-year period through distribution rates. On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated a provision of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” and remanded the matter to the PUCO for further consideration. On September 10, 2007, the Ohio Companies filed an application with the PUCO that requested the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. On January 9, 2008, the PUCO approved the Ohio Companies’ proposed fuel cost rider to recover increased fuel costs incurred during 2008, which was approximately $185 million. In addition, the PUCO ordered the Ohio Companies to file a separate application for an alternate recovery mechanism to collect the 2006 and 2007 deferred fuel costs. On February 8, 2008, the Ohio Companies filed an application proposing to recover $226 million of deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel rider. Recovery of the deferred fuel costs was also addressed in the Ohio Companies’ comprehensive ESP filing, which was subsequently withdrawn on December 22, 2008, and also as a part of the stipulation and recommendation which was attached to the amended application for an ESP, both as described below.

On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing to support a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of its investigation into the distribution rate request. In its reports, the PUCO Staff recommended a distribution rate increase in the range of $161 million to $180 million, with $108 million to $127 million for distribution revenue increases and $53 million for recovery of costs deferred under prior cases. During the evidentiary hearings and filing of briefs, the PUCO Staff decreased their recommended revenue increase to a range of $117 million to $135 million. 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 will go into effect 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.

On May 1, 2008, Governor Strickland signed SB221, which became effective on July 31, 2008. The bill requires all utilities to file an ESP with the PUCO, which must contain a proposal for the supply and pricing of retail generation. A utility may also file an MRO with the PUCO, in which it would have to prove the following objective market criteria: 1) the utility or its transmission service affiliate belongs to a FERC approved RTO, or there is comparable and nondiscriminatory access to the electric transmission grid; 2) the RTO has a market-monitor function and the ability to mitigate market power or the utility’s market conduct, or a similar market monitoring function exists with the ability to identify and monitor market conditions and conduct; and 3) a published source of information is available publicly or through subscription that identifies pricing information for traded electricity products, both on- and off-peak, scheduled for delivery two years into the future.

 

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On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and MRO. The MRO filing outlined a CBP for providing retail generation supply if the ESP is not approved and implemented. The CBP would use a “slice-of-system” approach where suppliers bid on tranches (approximately 100 MW) of the Ohio Companies’ total customer load. If the Ohio Companies proceed with the MRO option, successful bidders (including affiliates) would be required to post independent credit requirements and could be subject to significant collateral calls depending upon power price movement. The PUCO denied the MRO application on November 26, 2008.  The Ohio Companies filed an application for rehearing on December 23, 2008, which the PUCO granted on January 21, 2009, for the purpose of further consideration of the matter.

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. On December 19, 2008, the PUCO significantly modified and approved the ESP as modified.  On December 22, 2008, the Ohio Companies notified the PUCO that they were withdrawing and terminating the ESP application as allowed by the terms of SB221.  The Ohio Companies further notified the PUCO that, pursuant to SB221, the Ohio Companies would continue their current rate plan in effect and filed tariffs to continue those rates.

On December 31, 2008, the Ohio Companies conducted a CBP, using an RFP format administered by an independent third party, for the procurement of electric generation for retail customers from January 5, 2009 through March 31, 2009. Four qualified wholesale bidders were selected, including FES, for 97% of the tranches offered in the RFP. The average winning bid price was equivalent to a retail rate of 6.98 cents per kilowatt-hour. Subsequent to the RFP, the remaining 3% of the Ohio Companies’ wholesale energy and capacity needs were obtained through a bilateral contract with the lowest bidder in the RFP procurement. The power supply obtained through the foregoing processes provides generation service to the Ohio Companies’ retail customers who choose not to shop with alternative suppliers.

Following comments by other parties on the Ohio Companies’ December 22, 2008, filing which continued the current rate plan, the PUCO issued an Order on January 7, 2009, that prevented OE and TE from collecting RTC and discontinued the collection of two fuel riders for the Ohio Companies.  The Ohio Companies filed an application for rehearing on January 9, 2009, and also filed an application for a new fuel rider to recover the increased costs for purchasing power d uring the period January 1, 2009 through March 31, 2009. On January 14, 2009, the PUCO approved the Ohio Companies’ request for the new fuel rider, subject to further review, allowed current recovery of those costs for OE and TE, and allowed CEI to collect a portion of those costs currently and defer the remainder. The PUCO also ordered the Ohio Companies to file additional information in order for it to determine that the costs incurred are prudent and whether the recovery of such costs is necessary to avoid a confiscatory result.  The Ohio Companies filed an application for rehearing on that order on January 26, 2009. The applications for rehearing remain pending and the Ohio Companies are unable to predict the ultimate resolution of these issues.

On January 29, 2009, the PUCO ordered its Staff to develop a proposal to establish an ESP for the Ohio Companies and further ordered that a conference be held on February 5, 2009 to discuss the Staff’s proposal. The Ohio Companies, PUCO Staff, and other parties participated in that conference, and in a subsequent conference held on February 17, 2009. Following discussions with the Staff and other parties regarding the Staff’s proposal, 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 representing a diverse range of interests, which substantially reflected the terms as proposed by the Staff as modified through the negotiations of the parties. Specifically, the stipulated ESP provides that generation will be provided by FES at the average wholesale rate of the RFP process described above for April and May 2009 to the Ohio Companies for their non-shopping customers and that for the period of June 1, 2009 through May 31, 2011, retail generation prices will be based upon the outcome of a descending clock CBP on a slice-of-system basis. The PUCO may, at its discretion, phase-in a portion of any increase resulting from this CBP process by authorizing deferral of related purchased power costs, subject to specified limits. The proposed ESP further provides that the Ohio Companies will not seek a base distribution rate increase with an effective date before January 1, 2012, that CEI will agree to write-off approximately $215 million of its Extended RTC balance, and that the Ohio Companies will 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. If the Stipulated ESP is approved, one-time charges associated with implementing the ESP would be approximately $250 million (including the CEI Extended RTC balance), or $0.53 per share of common stock. The proposed ESP also addresses a number of other issues, including but not limited to, rate design for various customer classes, resolution of the prudence review described above and the collection of deferred costs that were approved in prior proceedings. On February 19, 2009, the PUCO attorney examiner issued an order setting this matter for hearing to begin on February 25, 2009.

 

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PPUC Rate Matters

Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. The fixed price under the agreement is expected to remain below wholesale market prices during the term of the agreement. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for their fixed income securities. 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 companies are expected to conclude by the end of February 2009. The TSCs include a component from under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received 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 February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and a three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. As part of the 2008 state budget negotiations, the Alternative Energy Investment Act was enacted in July 2008 creating a $650 million alternative energy fund to increase the development and use of alternative and renewable energy, improve energy efficiency and reduce energy consumption.

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. The bill addresses issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters and alternative energy. 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 guidelines for the filing of utilities’ energy efficiency and peak load reduction plans.

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 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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·

a minimum reduction in peak demand of 4.5% by May 31, 2013;

·

minimum reductions in energy consumption of 1% and 3% by May 31, 2011 and May 31, 2013, respectively; and

·

an expanded definition of alternative energy to include additional types of hydroelectric and biomass facilities.

Legislation addressing rate mitigation and the expiration of rate caps was not enacted in 2008 but may be considered in the legislative session which began in January 2009. While the form and impact of such legislation is uncertain, several legislators and the Governor have indicated their intent to address these issues in 2009.

On September 25, 2008, Met-Ed and Penelec filed a Voluntary Prepayment Plan with the PPUC that would provide an opportunity for residential and small commercial customers to prepay an amount on their monthly electric bills during 2009 and 2010 that would earn interest at 7.5% and be used to reduce electric rates in 2011 and 2012. Met-Ed, Penelec, OCA and OSBA have reached a settlement agreement on the Voluntary Prepayment Plan and have jointly requested that the PPUC approve the settlement. The ALJ issued a decision on January 29, 2009, recommending approval and adoption of the settlement without modification.

On February 20, 2009, Met-Ed and Penelec filed a generation procurement plan covering the period January 1, 2011 through May 31, 2013, with the PPUC. 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 October 2009.

NJBPU Rate Matters

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 December 31, 2008, the accumulated deferred cost balance totaled approximately $220 million.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004, supporting continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DRA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set.

On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. The NJBPU Staff circulated revised drafts of the proposal to interested stakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU accepted proposed rules for publication in the New Jersey Register on March 17, 2008. A public hearing on these proposed rules was held on April 23, 2008 and comments from interested parties were submitted by May 19, 2008.

New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments.

 

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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.

The EMP will be followed by appropriate legislation and regulation as necessary. 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 its intent to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. An estimated $40 million will be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations. Approximately $34 million will be spent implementing new demand response programs as well as expanding on existing programs. Another $11 million will be spent on energy efficiency, specifically replacing transformers and capacitor control systems and installing new LED street lights. The remaining $13 million will be spent on energy efficiency programs that will complement those currently being offered. Completion of the projects is dependent upon regulatory approval for full recovery of the costs associated with plan implementation.

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 Design

On January 31, 2005, certain PJM transmission owners made filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design; notably AEP, which proposed to create a "postage stamp", or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.

 

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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 FER C’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.

The FERC’s orders on PJM rate design will prevent the allocation of a portion of the revenue requirement of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce the costs of future transmission to be recovered from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding Judge 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. 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 (known as the RECB methodology) be retained.

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

Interconnection Agreement with AMP-Ohio

On May 29, 2008, TE filed with the FERC a proposed Notice of Cancellation effective midnight December 31, 2008, of the Interconnection Agreement with AMP-Ohio. AMP-Ohio protested this filing. TE also filed a Petition for Declaratory Order seeking a FERC ruling, in the alternative if cancellation is not accepted, of TE's right to file for an increase in rates effective January 1, 2009, for power provided to AMP-Ohio under the Interconnection Agreement. AMP-Ohio filed a pleading agreeing that TE may seek an increase in rates, but arguing that any increase is limited to the cost of generation owned by TE affiliates. On August 18, 2008, the FERC issued an order that suspended the cancellation of the Agreement for five months, to become effective on June 1, 2009, and established expedited hearing procedures on issues raised in the filing and TE’s Petition for Declaratory Order. On October 14, 2008, the parties filed a settlement agreement and mutual notice of cancellation of the Interconnection Agreement effective midnight December 31, 2008. On October 24, 2008 the presiding judge certified the settlement agreement as uncontested and on December 22, 2008, the FERC issued an order approving the uncontested settlement agreement. This latest action terminates the litigation and the Interconnection Agreement .

 

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Duquesne’s Request to Withdraw from PJM

On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join MISO. Duquesne’s proposed move would affect numerous FirstEnergy interests, including but not limited to the terms under which FirstEnergy’s Beaver Valley Plant would continue to participate in PJM’s energy markets.  FirstEnergy, therefore, intervened and participated fully in all of the FERC dockets that were related to Duquesne’s proposed move.

In November, 2008, Duquesne and other parties, including FirstEnergy, negotiated a settlement that would, among other things , allow for Duquesne to remain in PJM and provide for a methodology for Duquesne to meet the PJM capacity obligations for the 2011-2012 auction that excluded the Duquesne load. The settlement agreement was filed on December  10, 2008 and approved by the FERC in an order issued on January 29, 2009. The MISO opposed the settlement agreement pending resolution of exit fees alleged to be owed by Duquesne.  The FERC did not resolve this issue in its order.

Complaint against PJM RPM Auction

On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act.    On September  19, 2008, the FERC denied the RPM Buyers’ complaint. However, the FERC did grant the RPM Buyers’ request for a technical conference to review aspects of the RPM. 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 Bra ttle 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 talks. On February 9, 2009, PJM and a group of stakeholders submitted an offer of settlement.

On October 20, 2008, the RPM Buyers filed a request for rehearing of the FERC’s September 19, 2008 order. The FERC has not yet ruled on the rehearing request.

MISO Resource Adequacy Proposal

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

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 these compliance filings is not expected to delay the June 1, 2009, start date for MISO Resource Adequacy.

 

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FES Sales to Affiliates

On October 24, 2008, FES, on its own behalf and on behalf of its generation-controlling subsidiaries, filed an application with the FERC seeking a waiver of the affiliate sales restrictions between FES and the Ohio Companies. The purpose of the waiver is to ensure that FES will be able to continue supplying a material portion of the electric load requirements of the Ohio Companies in January 2009 pursuant to either an ESP or MRO as filed with the PUCO. FES previously obtained a similar waiver for electricity sales to its affiliates in New Jersey , New York , and Pennsylvania . On December 23, 2008, the FERC issued an order granting the waiver request and the Ohio Companies made the required compliance filing on December 30, 2008.

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 roughly two-thirds of these 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.

Capital Requirements

Anticipated capital expenditures for the Utilities, FES and FirstEnergy’s other subsidiaries for the years 2009 through 2013, excluding nuclear fuel, are shown in the following table. Such costs include expenditures for the betterment of existing facilities and for the construction of generating capacity, facilities for environmental compliance, transmission lines, distribution lines, substations and other assets.

		2008				Capital Expenditures Forecast
		Actual (1)				2009					2010-2013			Total
		(In millions)
OE		$	140			$	130			$	600			$	730
Penn			35				22				112				134
CEI			139				103				494				597
TE			57				48				202				250
JCP&L			177				160				812				972
Met-Ed			108				97				447				544
Penelec			129				122				484				606
ATSI			46				39				177				216
FGCO			1,037				635				1,373				2,008
NGC			115				243				1,323				1,566
Other subsidiaries			167				58				458				516
Total		$	2,150			$	1,657			$	6,482			$	8,139
(1)  Excludes nuclear fuel, the purchase of lessor equity interests in Beaver Valley Unit 2 and Perry ($438 million), and the acquisition of Signal Peak ($125 million).

During the 2009-2013 period, maturities of, and sinking fund requirements for, long-term debt of FirstEnergy and its subsidiaries are:

		Long-Term Debt Redemption Schedule
		2009					2010-2013			Total
		(In millions)
FirstEnergy		$	-			$	1,500			$	1,500
FES			42				254				296
OE			-				1				1
Penn (1)			1				5				6
CEI (2)			150				300				450
JCP&L			29				133				162
Met-Ed			-				250				250
Penelec			100				59				159
Other			1				64				65
Total		$	323			$	2,566			$	2,889
(1)  Penn has an additional $63 million due to associated companies in 2010-2013.
(2) CEI has an additional $85 million due to associated companies in 2010-2013.

 

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NGC's investments for additional nuclear fuel during the 2009-2013 period are estimated to be approximately $1.3 billion, of which about $342 million applies to 2009. During the same period, its nuclear fuel investments are expected to be reduced by approximately $1.0 billion and $137 million, respectively, as the nuclear fuel is consumed.

The following table displays operating lease commitments, net of capital trust cash receipts for the 2009-2013 period.

		Net Operating Lease Commitments
		2009					2010-2013			Total
		(In millions)
OE		$	103			$	390			$	493
CEI (1)			(38	)			(196	)			(234	)
TE			41				134				175
JCP&L			8				15				23
Met-Ed			4				7				11
Penelec			4				5				9
FESC			8				34				42
FGCO			176				787				963
NGC (2)			(103	)			(413	)			(516	)
Total		$	203			$	763			$	966
(1)  Reflects CEI's investment in Shippingport that purchased lease obligations bonds   issued on behalf of lessors in Bruce Mansfield Units 1, 2 and 3 sale and leaseback transactions. Effective October 16, 2007, CEI and TE assigned their leasehold interest s in the Bruce Mansfield Plant to FGCO.
(2)  Reflects NGC’s purchase of lessor equity interests in Beaver Valley Unit 2 and Perry in the second quarter of 2008.

FirstEnergy has been notified by the lessor of certain vehicle and equipment leases of its election to terminate the lease arrangements effective November 2009. FirstEnergy is currently pursuing replacement lease arrangements with alternative lessors. In the event that replacement lease arrangements are not secured, FirstEnergy would be required to purchase the vehicles and equipment under lease at their unamortized value of approximately $100 million upon termination of the lease.

FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligations and those of its subsidiaries. FirstEnergy and its subsidiaries' 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.  FirstEnergy also expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.

FirstEnergy had approximately $2.4 billion of short-term indebtedness as of Decem ber 31, 2008, comprised of $2.3  billion in borrowings under the $2.75   billion revolving line of credit described below and $102  million of other bank borrowings. Total short-term bank lines of committed credit to FirstEnergy , FES and the Utilities as of December   3 1, 2008 were approximately $4.0  billion.

FirstEnergy, along with certain of its subsidiaries, are party to a $2.75 billion five-year revolving credit facility. FirstEnergy has the ability to request an increase in the total commitments available under this fa cility 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 b orrowers, to an unlimited number of additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each b orrower are subject to a specified sub-limit, as well as applicable regulatory and other limitations.  The annual facility fee is 0.125%.

As of January 31, 2009 , FirstEnergy had $720 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 ava ilable liquidity as of January  31, 200 9 , is described in the following table.

 

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Company		Type		Maturity		Commitment				Available Liquidity as of January 31, 2009
						(In millions)
FirstEnergy (1)		Revolving		Aug. 2012		$	2,750			$	405
FirstEnergy and FES		Revolving		May 2009			300				300
FirstEnergy		Bank lines		Various (2)			120				20
FGCO		Term loan		Oct. 2009 (3)			300				300
Ohio and Pennsylvania Companies		Receivables financing		Various (4)			550				469
				Subtotal		$	4,020			$	1,494
				Cash			-				1,110
				Total		$	4,020			$	2,604

(1)

FirstEnergy Corp. and subsidiary borrowers.

(2)

$100 million matures November 30, 2009; $20 million uncommitted line of credit with no maturity date.

(3)

Drawn amounts are payable within 30 days and may not be re-borrowed.

(4)

$370 million expires February 22, 2010; $180 million expires December 18, 2009.

FirstEnergy's primary source of cash for continuing operations as a holding company is cash from the operations of its subsidiaries.  During 2008, the holding company received $995 million of cash dividends on common stock from its subsidiaries and paid $671 million in cash dividends to common shareholders.

As of December 31, 2008, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.8 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 OE, CEI and TE is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including 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, CEI and TE to incur additional secured debt not otherwise permitted by a specified exception of up to $168 million, $179 million and $117 million, respectively, as of December 31, 2008. On June 19, 2008, FGCO established an FMB indenture. Based upon its net earnings and available bondable property additions as of December 31, 2008, FGCO had the capability to issue $3.0 billion of additional FMBs under the terms of that indenture. Met-Ed and Penelec had the capability to issue secured debt of approximately $376 million and $318 million, respectively, under provisions of their senior note indentures as of December 31, 2008.

To the extent that coverage requirements or market conditions restrict the subsidiaries’ abilities to issue desired amounts of FMBs or preferred stock, they may seek other methods of financing. Such financings could include the sale of preferred and/or preference stock or of such other types of securities as might be authorized by applicable regulatory authorities which would not otherwise be sold and could result in annual interest charges and/or dividend requirements in excess of those that would otherwise be incurred.

On September 22, 2008, FirstEnergy and 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 may utilize the shelf registration statement to offer and sell unsecured, and in some cases, secured debt securities.

Nuclear Operating Licenses

Each of the nuclear units in the FES portfolio operates under a 40-year operating license granted by the NRC. The following table summarizes the current operating license expiration dates for FES’ nuclear facilities in service.

Station	In-Service Date	Current License Expiration
Beaver Valley Unit 1	1976	2016
Beaver Valley Unit 2	1987	2027
Perry	1986	2026
Davis-Besse	1977	2017

 

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In August 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The NRC is required by statute to provide an opportunity for members of the public to request a hearing on the application. No members of the public, however, requested a hearing on the Beaver   Valley license renewal application. On September 24, 2008, the NRC issued a draft supplemental Environmental Impact Statement for Beaver   Valley . FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and expects to obtain renewed licenses for the Beaver Valley Power Station in 2009. If renewed licenses are issued by the NRC, the Beaver Valley Power Station’s licenses would be extended until 2036 and 2047 for Units 1 and 2, respectively . FENOC’s application for operating license extensions for Beaver Valley Units 1 and 2 was accepted by the NRC on November 9, 2007. Similar applications are expected to be filed for Davis-Besse in 2010 and Perry in 2013. The NRC review process takes approximately two to three years from the docketing of an application. The license extension is for 20 years beyond the current license period.

Nuclear Regulation

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

Nuclear Insurance

The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $12.5 billion (assuming 104 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $300 million; and (ii) $12.2 billion provided by an industry retrospective rating plan required by the NRC pursuant thereto. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $118 million (but not more than $18 million per unit per year in the event of more than one incident) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Based on their present nuclear ownership and leasehold interests, FirstEnergy’s maximum potential assessment under these provisions would be $470 million (OE-$40 million, NGC-$408 million, and TE-$22 million) per incident but not more than $70 million (OE-$6 million, NGC-$61 million, and TE-$3 million) in any one year for each incident.

In addition to the public liability insurance provided pursuant to the Price-Anderson Act, FirstEnergy has also obtained insurance coverage in limited amounts for economic loss and property damage arising out of nuclear incidents. FirstEnergy is a member of Nuclear Electric Insurance Limited (NEIL) which provides coverage (NEIL I) for the extra expense of replacement power incurred due to prolonged accidental outages of nuclear units. Under NEIL I, FirstEnergy’s subsidiaries have policies, renewable yearly, corresponding to their respective nuclear interests, which provide an aggregate indemnity of up to approximately $2.0 billion (OE-$168 million, NGC-$1.7 billion, TE-$89 million) for replacement power costs incurred during an outage after an initial 20-week waiting period. Members of NEIL I pay annual premiums and are subject to assessments if losses exceed the accumulated funds available to the insurer. FirstEnergy’s present maximum aggregate assessment for incidents at any covered nuclear facility occurring during a policy year would be approximately $18 million (OE-$1 million, NGC-$16 million, and TE-$1 million).

FirstEnergy is insured as to its respective nuclear interests under property damage insurance provided by NEIL to the operating company for each plant. Under these arrangements, up to $2.8 billion of coverage for decontamination costs, decommissioning costs, debris removal and repair and/or replacement of property is provided. FirstEnergy pays annual premiums for this coverage and is liable for retrospective assessments of up to approximately $61 million (OE-$6 million, NGC-$52 million, TE-$2 million, Met Ed, Penelec and JCP&L-$1 million in total) during a policy year.

 

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

The NRC requires nuclear power plant licensees to obtain minimum property insurance coverage of $1.1 billion or the amount generally available from private sources, whichever is less. The proceeds of this insurance are required to be used first to ensure that the licensed reactor is in a safe and stable condition and can be maintained in that condition so as to prevent any significant risk to the public health and safety. Within 30 days of stabilization, the licensee is required to prepare and submit to the NRC a cleanup plan for approval. The plan is required to identify all cleanup operations necessary to decontaminate the reactor sufficiently to permit the resumption of operations or to commence decommissioning. Any property insurance proceeds not already expended to place the reactor in a safe and stable condition must be used first to complete those decontamination operations that are ordered by the NRC. FirstEnergy is unable to predict what effect these requirements may have on the availability of insurance proceeds.

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 $608 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 SO 2 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 SO 2 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 SO 2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NO X reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NO X reductions at FirstEnergy's facilities. The EPA's NO X Transport Rule imposes uniform reductions of NO X emissions (an approximate 85% reduction in utility plant NO X emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NO X emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NO X budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.

 

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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 NO X and SO 2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree are currently estimated to be $506 million for 2009-2010 (with $414 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above, but excludes the potential AQC expenditures related to Burger Units 4 and 5 described below. On September 8, 2008, the Environmental Enforcement Section of the DOJ sent a letter to OE regarding its view that the company was not in compliance with the Sammis NSR Litigation consent decree because the installation of an SNCR at Eastlake Unit 5 was not completed by December 31, 2006. However, the DOJ acknowledged that stipulated penalties could not apply under the terms of the Sammis NSR Litigation consent decree because Eastlake Unit 5 was idled on December 31, 2006 pending installation of the SNCR and advised that it had exercised its discretion not to seek any other penalties for this alleged non-compliance. OE disputed the DOJ's interpretation of the consent decree in a letter dated September 22, 2008. Although the Eastlake Unit 5 issue is no longer active, OE filed a dispute resolution petition on October 23, 2008, with the United States District Court for the Southern District of Ohio, due to potential impacts on its compliance decisions with respect to Burger Units 4 and 5. On December 23, 2008, OE withdrew its dispute resolution petition and subsequently filed a motion to extend the date (from December 31, 2008 to April 15, 2009), under the Sammis NSR Litigation consent decree, to elect for Burger Units 4 and 5 to permanently shut down those units by December 31, 2010, or to repower them or to install flue gas desulfurization (FGD) by later dates. On January 30, 2009, the Court issued an order extending the election date from December 31, 2008 to March 31, 2009.

 

On April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. Subsequently, on May 8, 2007, the EPA proposed to revise the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR.  On December 10, 2008, the EPA announced it would not finalize this proposed change to the NSR regulations.

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.

On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed. Specifically, New Jersey alleges that "modifications" at Portland Units 1 and 2 occurred between 1980 and 1995 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. On March 14, 2008, Met-Ed filed a motion to dismiss the citizen suit claims against it and a stipulation in which the parties agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the United States District Court. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. On October  30, 2008, the state of Connecticut filed a Motion to Intervene, but th e Court has yet to rule on Connecticut ’s Motion. 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 . 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.

 

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On June 11, 2008, the EPA issued a Notice and Finding of Violation to MEW alleging that "modifications" at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program . MEW is seeking indemnification from Penelec, 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. T he scope of Penelec’s indemnity obligation to and from MEW is disputed. Penelec is unable to predict the outcome of this matter.

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

In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR requires reductions of NO X and SO 2 emissions in two phases (Phase I in 2009 for NO X , 2010 for SO 2 and Phase II in 2015 for both NO X and SO 2 ), ultimately capping SO 2 emissions in affected states to just 2.5 million tons annually and NO X emissions to just 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” 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. The 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 SO 2 and NO X 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 United States moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the United States’ petition and denied the industry group’s petition.  Accordingly, the EPA could take regulatory action to promulgate new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with mercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately implemented.

Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. 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.

 

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Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG, including CO 2 , emitted by developed countries by 2012. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. However, the Bush administration had committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. Also, in an April 16, 2008 speech, former President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition, the EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity in the United States comes from renewable sources by 2012, and 25% by 2025; and implementing an economy-wide cap-and-trade program to reduce GHG emissions 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 Senate Environment and Public Works Committee has passed one such bill. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO 2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO 2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. On July 11, 2008, the EPA released an Advance Notice of Proposed Rulemaking, soliciting input from the public on the effects of climate change and the potential ramifications of regulation of CO 2 under the CAA.

FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO 2 emissions could require significant capital and other expenditures. The CO 2 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-CO 2 emitting gas-fired and nuclear generators.

Clean Water Act

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

On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 14, 2008, the Supreme Court of the United States granted a petition for a writ of certiorari to review one significant aspect of the Second Circuit Court’s opinion which is whether Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures.  Oral argument before the Supreme Court occurred on December 2, 2008 and a decision is anticipated during the first half of 2009. FirstEnergy is studying various control options and their costs and effectiveness. Depending on the results of such studies, the outcome of the Supreme Court’s review of the Second Circuit’s decision, the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

 

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.

 

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Regulation of Hazardous Waste

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

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of December 31, 2008, 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 agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seeks for these facilities.

The Utilities have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site may be liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of December 31, 2008, 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 $90 million have been accrued through December 31, 2008. Included in the total are accrued liabilities of approximately $56 million for environmental remediation of former manufactured gas plants in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

Fuel Supply

FES currently has long-term coal contracts with various terms to provide approximately 21.5 million tons of coal for the year 2009, approximately 98% of its 2009 coal requirements of 22 million tons. This contract coal is produced primarily from mines located in Ohio , Pennsylvania , Kentucky , West Virginia and Wyoming . The contracts expire at various times through December 31, 2030. See “Environmental Matters” for factors pertaining to meeting environmental regulations affecting coal-fired generating units.

I n July 2008, FEV entered into a joint venture with the Boich Companies, a Columbus, Ohio-based coal company, to acquire a majority stake in the Bull Mountain Mine Operations, now called Signal Peak, near Roundup, Montana. This transaction is part of FirstEnergy’s strategy to secure high-quality fuel supplies at attractive prices to maximize the capacity of its fossil generating plants. In a related transaction, FirstEnergy entered into a 15-year agreement to purchase up to 10 million tons of bituminous western coal annually from the mine. FirstEnergy also entered into agreements with the rail carriers associated with transporting coal from the mine to its generating stations, and expect s to begin taking delivery of the coal in late 2009 or early 2010. The joint venture has the right to resell Signal   Peak coal tonnage not used at FirstEnergy facilities and has call rights on such coal above certain levels.

FirstEnergy ha s contract s for all uranium requirements through 2010 and a portion of uranium material requirements through 2014. Conversion services contracts fully cover requirements through 2011 and partially fill requirements through 2015. Enrichment services are contracted for all of the enrichment requirements for nuclear fuel through 2014. A portion of enrichment requirements is also contracted for through 2020. Fabrication services for fuel assemblies are contracted for both Beaver   Valley units and Davis Besse through 2013 and through the current operating license period for Perry (through approximately 2026). The Davis-Besse fabrication contract also has an extension provision for services for three additional consecutive reload batches through the current operating license period (approximately 2017). In addition to the existing commitments, FirstEnergy intends to make additional arrangements for the supply of uranium and for the subsequent conversion, enrichment, fabrication, and waste disposal services.

On-site spent fuel storage facilities are expected to be adequate for Perry through 2011; facilities at Beaver Valley Units 1 and 2 are expected to be adequate through 2015 and 2010, respectively. Davis-Besse has adequate storage through the remainder of its current operating license period. After current on-site storage capacity at the plants is exhausted, additional storage capacity will have to be obtained either through plant modifications, interim off-site disposal, or permanent waste disposal facilities. FENOC is currently taking actions to extend the spent fuel storage capacity for Perry and Beaver   Valley . Plant modifications to increase the storage capacity of the existing spent fuel storage pool at Beaver Valley Unit 2 will be submitted to the NRC for approval during the first half of 2009, with implementation scheduled for 2010. Dry fuel storage is also being pursued at Perry and Beaver   Valley , with Perry implementation scheduled to begin in 2010.

 

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The Federal Nuclear Waste Policy Act of 1982 provides for the construction of facilities for the permanent disposal of high-level nuclear wastes, including spent fuel from nuclear power plants operated by electric utilities. NGC has contracts with the   DOE   for the disposal of spent fuel for Beaver   Valley , Davis-Besse and Perry. Yucca   Mountain   was approved in 2002 as a repository for underground disposal of spent nuclear fuel from nuclear power plants and high level waste from U.S. defense programs. The DOE submitted the license application for Yucca   Mountain to the NRC on June 3, 2008. Based on the DOE’s most recent published statements, the earlies t date that the Yucca   Mountain r epository will start receiving spent fuel is 2020. FirstEnergy intend s to make additional arrangements for storage capacity as a contingency for further delays with the DOE acceptance of spent fuel for disposal past 2020.

Fuel oil and natural gas are used primarily to fuel peaking units and/or to ignite the burners prior to burning coal when a coal-fired plant is restarted. Fuel oil requirements have historically been lo w and are forecasted to remain so; requirements are expected to average approximately 5 million gallons per year over the next five years. Due to the volatility of fuel oil price s , F irstEnergy has adopted a strategy of either purchasing fixed - priced oil for inventory or using financial instruments to hedge against price risk . Natural gas is consumed primarily by peaking units, and the demand is forecast ed to range from approximately 3.5 million cubic feet (Mcf) in 2009 to 2.7 Mcf in 2010. Because of high price volatility and the unpredictability of unit dispatch, natural gas futures are purchased based on forecasted demand to hedge against price movements .

System Demand

The 2008 net maximum hourly demand for each of the Utilities was: OE–5,579 MW on June 9, 2008; Penn–1,063 MW on June 9, 2008; CEI–4,295 MW on June 9, 2008; TE–2,050 MW on June 9, 2008; JCP&L–6,299 MW on June 10, 2008; Met-Ed–3,045 MW on June 10, 2008; and Penelec–2,880 MW on June 9, 2008 .

Supply Plan

Regulated Commodity Sourcing

The Utilities have a default service obligation to provide the required power supply to non-shopping customers who have elected to continue to receive service under regulated retail tariffs. The volume of these sales can vary depending on the level of shopping that occurs. Supply plans vary by state and by service territory. JCP&L’s default service supply is secured through a statewide competitive procurement process approved by the NJBPU. Penn’s default service supply is provided through a competitive procurement process approved by the PPUC. For the first quarter of 2009, the default service supply for the Ohio Companies was sourced 4% from the spot market and 96% through a competitive procurement process. Absent resolution of the ESP or MRO, the Ohio Companies anticipate conducting a similar CBP for the period beginning April 1, 2009. The default service supply for Met-Ed and Penelec is secured through a series of existing, long-term bilateral purchase contracts with unaffiliated suppliers, and through a FERC-approved agreement with FES. If any unaffiliated suppliers fail to deliver power to any one of the Utilities’ service areas, the Utility serving that area may need to procure the required power in the market in their role as a PLR.

Unregulated Commodity Sourcing

FES has retail and wholesale competitive load-serving obligations in Ohio, New Jersey, Maryland, Pennsylvania, Michigan and Illinois serving both affiliated and non-affiliated companies. FES provides energy products and services to customers under various PLR, shopping, competitive-bid and non-affiliated contractual obligations. In 2008, FES’ generation service to affiliated companies was approximately 95% of its total generation obligation. Depending upon the resolution of regulatory proceedings relating to how the Ohio Companies will obtain their supply and thereafter the results of any CBP or other procurement process implemented in accordance with PUCO requirements, FES’ service to affiliated companies may decrease, making more power available to the competitive wholesale markets and potentially subjecting FES to greater volatility in the prices it receives for its power. Geographically, approximately 68% of FES’ obligation is located in the MISO market area and 32% is located in the PJM market area.

FES provides energy and energy related services, including the generation and sale of electricity and energy planning and procurement through retail and wholesale competitive supply arrangements. FES controls (either through ownership, lease, affiliated power contracts or participation in OVEC) 13,973 MW of installed generating capacity. FES supplies the power requirements of its competitive load-serving obligations through a combination of subsidiary-owned generation, non-affiliated contracts and spot market transactions.

 

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Regional Reliability

FirstEnergy’s operating companies are located within MISO and PJM and operate under the reliability oversight of a regional entity known as Reliability First . This regional entity operates under the oversight of the NERC in accordance with a Delegation Agreement approved by the FERC. Reliability First began operations under the NERC on January 1, 2006. On July 20, 2006, the NERC was certified by the FERC as the ERO in the United States pursuant to Section 215 of the Federal Power Act and Reliability First was certified as a regional entity. Reliability First represents the consolidation of the ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils into a single regional reliability organization.

Competition

As a result of actions taken by state legislative bodies, major changes in the electric utility business have occurred in portions of the United States, including Ohio, New Jersey and Pennsylvania where FirstEnergy’s utility subsidiaries operate. These changes have altered the way traditional integrated utilities conduct their business. FirstEnergy has aligned its business units to accommodate its retail strategy and participate in the competitive electricity marketplace (see Strategy and Outlook in the 2008 Annual Report of FirstEnergy). FirstEnergy’s Competitive Energy Services segment participates in deregulated energy markets in Ohio, Pennsylvania, Maryland, Michigan, and Illinois through FES.

In New Jersey, JCP&L has procured electric supply to serve its BGS customers since 2002 through a statewide auction process approved by the NJBPU. The auction is designed to procure supply for BGS customers at a cost reflective of market conditions.

FirstEnergy remains focused on managing the transition to competitive markets for electricity in Ohio and Pennsylvania.  On May 1, 2008, the Governor of Ohio signed SB221 into law, which became effective July 31, 2008. The new law provides two options for pricing generation in 2009 and beyond – through a negotiated rate plan or a competitive bidding process (see PUCO Rate Matters above).  In Pennsylvania, all electric distribution companies will be required to secure generation for customers in competitive markets by 2011.  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. The new law outlines a competitive procurement process and sets targets for energy efficiency and conservation (see PPUC Rate Matters above).

Research and Development

The Utilities participate in the funding of EPRI, which was formed for the purpose of expanding electric research and development under the voluntary sponsorship of the nation’s electric utility industry - public, private and cooperative. Its goal is to mutually benefit utilities and their customers by promoting the development of new and improved technologies to help the utility industry meet present and future electric energy needs in environmentally and economically acceptable ways. EPRI conducts research on all aspects of electric power production and use, including fuels, generation, delivery, energy management and conservation, environmental effects and energy analysis. The majority of EPRI’s research and development projects are directed toward practical solutions and their applications to problems currently facing the electric utility industry.

FirstEnergy also participates in other research and development initiatives with industry research consortiums and universities, including for the development of carbon capture and coal-based fuel cell technologies.

 

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Executive Officers

Name		Age		Positions Held During Past Five Years		Dates
A. J. Alexander		57		President and Chief Executive Officer		2004-present
				President and Chief Operating Officer		*-2004
W. D. Byrd		54		Vice President, Corporate Risk & Chief Risk Officer Director – Rates Strategy Director – Commodity Supply		2007-present 2004-2007 *-2004
L. M. Cavalier		57		Senior Vice President – Human Resources Vice President – Human Resources		2005-present *-2005
M. T. Clark		58		Executive Vice President – Strategic Planning & Operations Senior Vice President – Strategic Planning & Operations Vice President – Business Development		2008-present 2004-2008 *-2004
D. S. Elliott (B)		54		President – Pennsylvania Operations		2005-present
				Senior Vice President		*-2005
R. R. Grigg (A)(B)		60		Executive Vice President and President-FirstEnergy Utilities		2008-present
				Executive Vice President and Chief Operating Officer		2004-2008
J. J. Hagan		58		President and Chief Executive Officer – WE Generation   President and Chief Nuclear Officer – FENOC Senior Vice President and Chief Operating Officer – FENOC Senior Vice President - FENOC		*-2004   2007-present 2005-2007 *-2005
C. E. Jones (A)(B)		53		Senior Vice President – Energy Delivery & Customer Service (E) President – FirstEnergy Solutions Senior Vice President – Energy Delivery & Customer Service		2009-present 2007-2009 *-2007
C. D. Lasky (D)		46		Vice President – Fossil Operations		2008-present
				Vice President – Fossil Operations & Air Quality Compliance		2004-2008
				Plant Director		*-2004
G. R. Leidich		58		Executive Vice President & President – FirstEnergy Generation		2008-present
				Senior Vice President – Operations President and Chief Nuclear Officer – FENOC		2007-2008 *-2007
D. C. Luff		61		Senior Vice President – Governmental Affairs		2007-present
				Vice President		*-2007
R. H. Marsh (A)(B)(D)		58		Senior Vice President and Chief Financial Officer		*-present
S. E. Morgan (C)(F)		58		President – JCP&L Vice President – Energy Delivery		2004-present *-2004
J. M. Murray (A)(G)		62		President – Ohio Operations Regional President – Toledo Edison Company Regional President – West		2005-present 2004-2005 *-2004
J. F. Pearson (A)(B)(D)		54		Vice President and Treasurer		2006-present
				Treasurer Group Controller – Strategic Planning and Operations Group Controller  – FirstEnergy Solutions		2005-2006 2004-2005 *-2004
D. R. Schneider (D)		47		President – FirstEnergy Solutions (E) Senior Vice President – Energy Delivery & Customer Service Vice President – Energy Delivery Vice President – Commodity Operations Vice President  – Fossil Operations		2009-present 2007-2009 2006-2007 2004-2006 *-2004
L.L. Vespoli (A)(B)(D)		49		Executive Vice President and General Counsel		2008-present
				Senior Vice President and General Counsel		*-2008
H. L. Wagner (A)(B)(D)		56		Vice President, Controller and Chief Accounting Officer		*-present
T. M. Welsh		59		Senior Vice President – Assistant to CEO Senior Vice President Vice President		2007-present 2004-2007 *-2004

(A) Denotes executive officers of OE, CEI and TE.		(E) Position effective February 2, 2009.
(B) Denotes executive officers of Met-Ed and Penelec.		(F) Retiring, September 1, 2009.
(C) Denotes executive officer of JCP&L		(G) Retiring, June 1, 2009.
(D) Denotes executive officers of FES.		*  Indicates position held at least since January 1, 2004.

 

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Employees

As of January 1, 2009, FirstEnergy’s subsidiaries had a total of 14,698 employees located in the United States as follows:

		Total				Bargaining Unit
		Employees				Employees
FESC			3,355				250
OE			1,328				770
CEI			1,010				651
TE			445				321
Penn			223				165
JCP&L			1,470				1,113
Met-Ed			776				536
Penelec			994				664
ATSI			43				-
FES			219				-
FGCO			2,006				1,283
FENOC			2,829				1,031
Total			14,698				6,784

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district Court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. A final order identifying the individual damage amounts was issued on October 31, 2007. The award appeal process was initiated. The union filed a motion with the federal Court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. The Court has yet to render its decision. JCP&L recognized a liability for the potential $16 million award in 2005.

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

FirstEnergy Web Site

Each of the registrant’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are also made available free of charge on or through FirstEnergy’s internet Web site at www.firstenergycorp.com. These reports are posted on the Web site as soon as reasonably practicable after they are electronically filed with the SEC. Information contained on FirstEnergy’s Web site shall not be deemed incorporated into, or to be part of, this report.

ITEM 1A. RISK FACTORS

We operate in a business environment that involves significant risks, many of which are beyond our control. The following risk factors and all other information contained in this report should be considered carefully when evaluating FirstEnergy and our subsidiaries. These risk factors could affect our financial results and cause such results to differ materially from those expressed in any forward-looking statements made by or on behalf of us. Below, we have identified risks we currently consider material. However, our business, financial condition, cash flows or results of operations could be affected materially and adversely by additional risks not currently known to us or that we deem immaterial at this time. Additional information on risk factors is included in "Item 1. Business" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and in other sections of this Form 10-K that include forward-looking and other statements involving risks and uncertainties that could impact our business and financial results.

 

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Risks Related to Business Operations

Risks Arising from the Reliability of Our Power Plants and Transmission and Distribution Equipment

Operation of generation, transmission and distribution facilities involves risk, including the potential breakdown or failure of equipment or processes, fuel supply or transportation disruptions, accidents, labor disputes or work stoppages by employees, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental limitations and governmental interventions, and performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt generation, transmission and distribution delivery systems. Because our transmission facilities are interconnected with those of third parties, the operation of our facilities could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.

Operation of our power plants below expected capacity levels could result in lost revenues and increased expenses, including higher maintenance costs. Unplanned outages of generating units and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of our business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues as a result of selling fewer MWH or may require us to incur significant costs as a result of operating our higher cost units or obtaining replacement power from third parties in the open market to satisfy our forward power sales obligations.   Moreover, if we were unable to perform under contractual obligations, penalties or liability for damages could result. FES, FGCO and the Ohio Companies are exposed to losses under their applicable sale-leaseback arrangements for generating facilities upon the occurrence of certain contingent events that could render those facilities worthless. Although we believe these types of events are unlikely to occur, FES, FGCO and the Ohio Companies have a maximum exposure to loss under those provisions of approximately $1.3 billion for FES, $800 million for OE and an aggregate of $700 million for TE and CEI as co-lessees.

We remain obligated to provide safe and reliable service to customers within our franchised service territories. Meeting this commitment requires the expenditure of significant capital resources. Failure to provide safe and reliable service and failure to meet regulatory reliability standards due to a number of factors, including, but not limited to, equipment failure and weather, could adversely affect our operating results through reduced revenues and increased capital and operating costs and the imposition of penalties/fines or other adverse regulatory outcomes.

Changes in Commodity Prices Could Adversely Affect Our Profit Margins

 

We purchase and sell electricity in the competitive wholesale and retail markets. Increases in the costs of fuel for our generation facilities (particularly coal, uranium and natural gas) can affect our profit margins. Changes in the market price of electricity, which are affected by changes in other commodity costs and other factors, may impact our results of operations and financial position by increasing the amount we pay to purchase power to supply PLR and default service obligations in Ohio and Pennsylvania.  In addition, the weakening global economy could lead to lower international demand for coal, oil and natural gas, which may lower fossil fuel prices and put downward pressure on electricity prices.

Electricity and fuel prices may fluctuate substantially over relatively short periods of time for a variety of reasons, including:

▪

changing weather conditions or seasonality;

▪

changes in electricity usage by our customers;

▪

illiquidity in wholesale power and other markets;

▪

transmission congestion or transportation constraints, inoperability or inefficiencies;

▪

availability of competitively priced alternative energy sources;

▪

changes in supply and demand for energy commodities;

▪

changes in power production capacity;

▪

outages at our power production facilities or those of our competitors;

▪

changes in production and storage levels of natural gas, lignite, coal, crude oil and refined products; and

▪

natural disasters, wars, acts of sabotage, terrorist acts, embargoes and other catastrophic events.

 

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We Are Exposed to Operational, Price and Credit Risks Associated With Selling and Marketing Products in the Power Markets That We Do Not Always Completely Hedge Against

We purchase and sell power at the wholesale level under market-based tariffs authorized by the FERC, and also enter into short-term agreements to sell available energy and capacity from our generation assets. If we are unable to deliver firm capacity and energy under these agreements, we may be required to pay damages. These damages would generally be based on the difference between the market price to acquire replacement capacity or energy and the contract price of the undelivered capacity or energy. Depending on price volatility in the wholesale energy markets, such damages could be significant . Extreme weather conditions, unplanned power plant outages, transmission disruptions, and other factors could affect our ability to meet our obligations, or cause increases in the market price of replacement capacity and energy.

We attempt to mitigate risks associated with satisfying our contractual power sales arrangements by reserving generation capacity to deliver electricity to satisfy our net firm sales contracts and, when necessary, by purchasing firm transmission service. We also routinely enter into contracts, such as fuel and power purchase and sale commitments, to hedge our exposure to fuel requirements and other energy-related commodities. We may not, however, hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility, our results of operations and financial position could be negatively affected.

The Use of Derivative Contracts by Us to Mitigate Risks Could Result in Financial Losses That May Negatively Impact our Financial Results

We use a variety of non-derivative and derivative instruments, such as swaps, options, futures and forwards, to manage our commodity and financial market risks. In the absence of actively quoted market prices and pricing information from external sources, the valuation of some of these derivative instruments involves management's judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of some of these contracts.  Also, we could recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform.

Our Risk Management Policies Relating to Energy and Fuel Prices, and Counterparty Credit Are by Their Very Nature Risk Related, and We Could Suffer Economic Losses Despite Such Policies

We attempt to mitigate the market risk inherent in our energy, fuel and debt positions. Procedures have been implemented to enhance and monitor compliance with our risk management policies, including validation of transaction and market prices, verification of risk and transaction limits, sensitivity analysis and daily portfolio reporting of various risk measurement metrics. Nonetheless, we cannot economically hedge all of our exposures in these areas and our risk management program may not operate as planned. For example, actual electricity and fuel prices may be significantly different or more volatile than the historical trends and assumptions reflected in our analyses. Also, our power plants might not produce the expected amount of power during a given day or time period due to weather conditions, technical problems or other unanticipated events, which could require us to make energy purchases at higher prices than the prices under our energy supply contracts. In addition, the amount of fuel required for our power plants during a given day or time period could be more than expected, which could require us to buy additional fuel at prices less favorable than the prices under our fuel contracts. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events lead to greater losses or costs than our risk management positions were intended to hedge.

Our risk management activities, including our power sales agreements with counterparties, rely on projections that depend heavily on judgments and assumptions by management of factors such as future market prices and demand for power and other energy-related commodities.  These factors become more difficult to predict and the calculations become less reliable the further into the future these estimates are made.  Even when our policies and procedures are followed and decisions are made based on these estimates, results of operations may be diminished if the judgments and assumptions underlying those calculations prove to be inaccurate.

We also face credit risks from parties with whom we contract who could default in their performance, in which cases we could be forced to sell our power into a lower-priced market or make purchases in a higher-priced market than existed at the time of executing the contract. Although we have established risk management policies and programs, including credit policies to evaluate counterparty credit risk, there can be no assurance that we will be able to fully meet our obligations, that we will not be required to pay damages for failure to perform or that we will not experience counterparty non-performance or that we will collect for voided contracts. If counterparties to these arrangements fail to perform, we may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices. In that event, our financial results could be adversely affected.

 

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Nuclear Generation Involves Risks that Include Uncertainties Relating to Health and Safety, Additional Capital Costs, the Adequacy of Insurance Coverage and Nuclear Plant Decommissioning

We are subject to the risks of nuclear generation, including but not limited to the following:

▪

the potential harmful effects on the environment and human health resulting from unplanned radiological releases associated with the operation of our nuclear facilities and the storage, handling and disposal of radioactive materials;

▪

limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations or those of others in the United States;

▪

uncertainties with respect to contingencies and assessments if insurance coverage is inadequate; and

▪

uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed operation including increases in minimum funding requirements or costs of completion.

The NRC has broad authority under federal law to impose licensing security and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines and/or shut down a unit, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants, including ours.  Also, a serious nuclear incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or relicensing of any domestic nuclear unit.

Our nuclear facilities are insured under NEIL policies issued for each plant. Under these policies, up to $2.8 billion of insurance coverage is provided for property damage and decontamination and decommissioning costs. We have also obtained approximately $2.0 billion of insurance coverage for replacement power costs. Under these policies, we can be assessed a maximum of approximately $79 million for incidents at any covered nuclear facility occurring during a policy year that are in excess of accumulated funds available to the insurer for paying losses.

The Price-Anderson Act limits the public liability that can be assessed with respect to a nuclear power plant to $12.5 billion (assuming 104 units licensed to operate in the United States) for a single nuclear incident, which amount is covered by:  (i) private insurance amounting to $300.0 million; and (ii) $12.2 billion provided by an industry retrospective rating plan. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $117.5 million (but not more than $17.5 million per year) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Our maximum potential exposure under these provisions would be $470.0 million per incident but not more than $70.0 million in any one year.

Capital Market Performance and Other Changes May Decrease the Value of Decommissioning Trust Fund, Pension Fund Assets and Other Trust Funds Which Then Could Require Significant Additional Funding

Our financial statements reflect the values of the assets held in trust to satisfy our obligations to decommission our nuclear generation facilities and under pension and other post-retirement benefit plans. The value of certain of the assets held in these trusts do not have readily determinable market values. Changes in the estimates and assumptions inherent in the value of these assets could affect the value of the trusts.  If the value of the assets held by the trusts declines by a material amount, our funding obligation to the trusts could materially 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 assets that are held in trust to satisfy future obligations to decommission our nuclear plants, to pay pensions to our retired employees and to pay other funded obligations. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. Forecasting investment earnings and costs to decommission nuclear generating stations, to pay future pensions and other obligations requires significant judgment, and actual results may differ significantly from current estimates. Capital market conditions that generate investment losses or greater liability levels can negatively impact our results of operations and financial position.

 

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We Could be Subject to Higher Costs and/or Penalties Related to Mandatory NERC/FERC Reliability Standards

As a result of the EPACT, owners, operators, and users of the bulk electric system are subject to mandatory reliability standards promulgated by NERC and approved by FERC. The standards are based on the functions that need to be performed to ensure that the bulk electric system operates reliably. Compliance with new reliability standards may subject us to higher operating costs and/or increased capital expenditures. If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties.

Reliability standards that were historically subject to voluntary compliance are now mandatory and could subject us to potential civil penalties for violations which could negatively impact our business.  The FERC can now impose penalties of $1.0 million per day for failure to comply with these mandatory electric reliability standards.

In addition to direct regulation by the FERC, we are also subject to rules and terms of participation imposed and administered by various RTOs and ISOs. Although these entities are themselves ultimately regulated by the FERC, they can impose rules, restrictions and terms of service that are quasi-regulatory in nature and can have a material adverse impact on our business. For example, the independent market monitors of ISOs and RTOs may impose bidding and scheduling rules to curb the potential exercise of market power and to ensure the market functions. Such actions may materially affect our ability to sell, and the price we receive for, our energy and capacity.

We Rely on Transmission and Distribution Assets That We Do Not Own or Control to Deliver Our Wholesale Electricity. If Transmission is Disrupted Including Our Own Transmission, or Not Operated Efficiently, or if Capacity is Inadequate, Our Ability to Sell and Deliver Power May Be Hindered

We depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity we sell. If transmission is disrupted (as a result of weather, natural disasters or other reasons) or not operated efficiently by independent system operators, in applicable markets, or if capacity is inadequate, our ability to sell and deliver products and satisfy our contractual obligations may be hindered, or we may be unable to sell products on the most favorable terms. In addition, in certain of the markets in which we operate, we may be deemed responsible for congestion costs if we schedule delivery of power between congestion zones during periods of high demand.  If we are unable to recover for such congestion costs in retail rates, our financial results could be adversely affected.

 

Demand for electricity within our utilities’ service areas could stress available transmission capacity requiring alternative routing or curtailing electricity usage that may increase operating costs or reduce revenues with adverse impacts to results of operations. In addition, as with all utilities, potential concerns over transmission capacity could result in MISO, PJM or the FERC requiring us to upgrade or expand our transmission system, requiring additional capital expenditures.

The FERC requires wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, it is possible that fair and equal access to transmission systems will not be available or that sufficient transmission capacity will not be available to transmit electricity as we desire. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities in specific markets or whether independent system operators in applicable markets will operate the transmission networks, and provide related services, efficiently.

Disruptions in Our Fuel Supplies Could Occur, Which Could Adversely Affect Our Ability to Operate Our Generation Facilities and Impact Financial Results

We purchase fuel from a number of suppliers. The lack of availability of fuel at expected prices, or a disruption in the delivery of fuel which exceeds the duration of our on-site fuel inventories, including disruptions as a result of weather, increased transportation costs or other difficulties, labor relations or environmental or other regulations affecting our fuel suppliers, could cause an adverse impact on our ability to operate our facilities, possibly resulting in lower sales and/or higher costs and thereby adversely affect our results of operations. Operation of our coal-fired generation facilities is highly dependent on our ability to procure coal. Although we have long-term contracts in place for our coal and coal transportation needs, power generators in the Midwest and the Northeast have experienced significant pressures on available coal supplies that are either transportation or supply related. If prices for physical delivery are unfavorable, our financial condition, results of operations and cash flows could be materially adversely affected.

 

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Temperature Variations as well as Weather Conditions or other Natural Disasters Could Have a Negative Impact on Our Results of Operations and Demand Significantly Below or Above our Forecasts Could Adversely Affect our Energy Margins

Weather conditions directly influence the demand for electric power. Demand for power generally peaks during the summer months, with market prices also typically peaking at that time. Overall operating results may fluctuate based on weather conditions. In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder. Severe weather, such as tornadoes, hurricanes, ice or snow storms, or droughts or other natural disasters, may cause outages and property damage that may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned under these conditions would be particularly burdensome during a peak demand period.

Customer demand that we satisfy pursuant to our default service tariffs could change as a result of severe weather conditions or other circumstances over which we have no control. We satisfy our electricity supply obligations through a portfolio approach of providing electricity from our generation assets, contractual relationships and market purchases. A significant increase in demand could adversely affect our energy margins if we are required under the terms of the default service tariffs to provide the energy supply to fulfill this increased demand at capped rates, which we expect would remain below the wholesale prices at which we would have to purchase the additional supply if needed or, if we had available capacity, the prices at which we could otherwise sell the additional supply. Accordingly, any significant change in demand could have a material adverse effect on our results of operations and financial position.

We Are Subject to Financial Performance Risks Related to General Economic Cycles and also Related to Heavy Manufacturing Industries such as Automotive and Steel

Our business follows the economic cycles of our customers. Declines in demand for electricity as a result of economic downturns would be expected to reduce overall electricity sales and reduce our revenues. Economic conditions also impact the rate of delinquent customer accounts receivable, further increasing our costs. A decrease in electric generation sales volume has been, and is expected to continue to be, influenced by circumstances in automotive, steel and other heavy industries.

Increases in Customer Electric Rates and the Impact of the Economic Downturn May Lead to a Greater Amount of Uncollectible Customer Accounts

Our utility operations are impacted by the economic conditions in our service territories and those conditions could negatively impact our collections of accounts receivable which could adversely impact our financial condition, results of operations and cash flows.

The Goodwill of One or More of Our Operating Subsidiaries May Become Impaired, Which Would Result in Write-Offs of the Impaired Amounts

Goodwill could become impaired at one or more of our operating subsidiaries. The actual timing and amounts of any goodwill impairments in future years would depend on many uncertainties, including changing interest rates, utility sector market performance, our capital structure, market prices for power, results of future rate proceedings, operating and capital expenditure requirements, the value of comparable utility acquisitions and other factors.

We Face Certain Human Resource Risks Associated with the Availability of Trained and Qualified Labor to Meet Our Future Staffing Requirements

We are challenged to find ways to retain our aging skilled workforce while recruiting new talent to mitigate losses in critical knowledge and skills due to retirements. Mitigating these risks could require additional financial commitments.

Significant Increases in Our Operation and Maintenance Expenses, Including Our Health Care and Pension Costs, Could Adversely Affect Our Future Earnings and Liquidity

We continually focus on limiting, and reducing where possible, our operation and maintenance expenses. However, we expect to continue to face increased cost pressures, including health care and pension costs. We have experienced significant health care cost inflation in the last few years, and we expect our cash outlay for health care costs, including prescription drug coverage, to continue to increase despite measures that we have taken and expect to take requiring employees and retirees to bear a higher portion of the costs of their health care benefits. The measurement of our expected future health care and pension obligations and costs is highly dependent on a variety of assumptions, many of which relate to factors beyond our control. These assumptions include investment returns, interest rates, health care cost trends, benefit design changes, salary increases, the demographics of plan participants and regulatory requirements. If actual results differ materially from our assumptions, our costs could be significantly increased.

 

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Our Business is Subject to the Risk that Sensitive Customer Data May be Compromised, Which Could Result in an Adverse Impact to Our Reputation and/or Results of Operations

Our business requires access to sensitive customer data, including personal and credit information, in the ordinary course of business. A security breach may occur, despite security measures taken by us and required of vendors. If a significant or widely publicized breach occurred, our business reputation may be adversely affected, customer confidence may be diminished, or we may become subject to legal claims, fines or penalties, any of which could have a negative impact on our business and/or results of operations.

Acts of War or Terrorism Could Negatively Impact Our Business

The possibility that our infrastructure, such as electric generation, transmission and distribution facilities, or that of an interconnected company, could be direct targets of, or indirect casualties of, an act of war or terrorism, could result in disruption of our ability to generate, purchase, transmit or distribute electricity. Any such disruption could result in a decrease in revenues and additional costs to purchase electricity and to replace or repair our assets, which could have a material adverse impact on our results of operations and financial condition.

Capital Improvements and Construction Projects May Not be Completed Within Forecasted Budget, Schedule or Scope Parameters

Our business plan calls for extensive capital investments, including the installation of environmental control equipment, as well as other initiatives. We may be exposed to the risk of substantial price increases in the costs of labor and materials used in construction. We have engaged numerous contractors and entered into a large number of agreements to acquire the necessary materials and/or obtain the required construction-related services. As a result, we are also exposed to the risk that these contractors and other counterparties could breach their obligations to us. Such risk could include our contractors’ inabilities to procure sufficient skilled labor as well as potential work stoppages by that labor force. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices, with resulting delays in those and other projects. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than these mitigation provisions. This could have negative financial impacts such as incurring losses or delays in completing construction projects.

 

Changes in Technology may Significantly Affect Our Generation Business by Making Our Generating Facilities Less Competitive

 

We primarily generate electricity at large central facilities. This method results in economies of scale and lower costs than newer technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in technologies will reduce their costs to levels that are equal to or below that of most central station electricity production, which could have a material adverse effect on our results of operations.

We May Acquire Assets That Could Present Unanticipated Issues for our Business in the Future, Which Could Adversely Affect Our Ability to Realize Anticipated Benefits of Those Acquisitions

Asset acquisitions involve a number of risks and challenges, including: management attention; integration with existing assets; difficulty in evaluating the requirements associated with the assets prior to acquisition, operating costs, potential environmental and other liabilities, and other factors beyond our control; and an increase in our expenses and working capital requirements.  Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows or realize other anticipated benefits from any such asset acquisition.

Risks Associated With Regulation

Complex and Changing Government Regulations Could Have a Negative Impact on Our Results of Operations

 

We are subject to comprehensive regulation by various federal, state and local regulatory agencies that significantly influence our operating environment. Changes in, or reinterpretations of, existing laws or regulations, or the imposition of new laws or regulations, could require us to incur additional costs or change the way we conduct our business, and therefore could have an adverse impact on our results of operations.

 

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Our utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. Thus, the rates a utility is allowed to charge may or may not be set to recover its expenses at any given time. Additionally, there may also be a delay between the timing of when costs are incurred and when costs are recovered. While rate regulation is premised on providing an opportunity to earn a reasonable return on invested capital and recovery of operating expenses, there can be no assurance that the applicable regulatory commission will determine that all of our costs have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs in a timely manner.

Regulatory Changes in the Electric Industry, Including a Reversal, Discontinuance or Delay of the Present Trend Toward Competitive Markets, Could Affect Our Competitive Position and Result in Unrecoverable Costs Adversely Affecting Our Business and Results of Operations

As a result of restructuring initiatives, changes in the electric utility business have occurred, and are continuing to take place throughout the United States, including Ohio, Pennsylvania and New Jersey. These changes have resulted, and are expected to continue to result, in fundamental alterations in the way utilities conduct their business.

Some states that have deregulated generation service have experienced difficulty in transitioning to market-based pricing. In some instances, state and federal government agencies and other interested parties have made proposals to delay market restructuring or even re-regulate areas of these markets that have previously been deregulated. Although we expect wholesale electricity markets to continue to be competitive, proposals to re-regulate our industry may be made, and legislative or other action affecting the electric power restructuring process may cause the process to be delayed, discontinued or reversed in the states in which we currently, or may in the future, operate. Such delays, discontinuations or reversals of electricity market restructuring in the markets in which we operate could have an adverse impact on our results of operations and financial condition.

The FERC and the U.S. Congress propose changes from time to time in the structure and conduct of the electric utility industry. If the restructuring, deregulation or re-regulation efforts result in decreased margins or unrecoverable costs, our business and results of operations would be adversely affected. We cannot predict the extent or timing of further efforts to restructure, deregulate or re-regulate our business or the industry.

The Prospect of Rising Rates Could Prompt Legislative or Regulatory Action to Restrict or Control Such Rate Increases.  This In Turn Could Create Uncertainty Affecting Planning, Costs and Results of Operations and May Adversely Affect the Utilities’ Ability to Recover Their Costs, Maintain Adequate Liquidity and Address Capital Requirements

 

Increases in utility rates, such as may follow a period of frozen or capped rates, can generate pressure on legislators and regulators to take steps to control those increases. Such efforts can include some form of rate increase moderation, reduction or freeze. The public discourse and debate can increase uncertainty associated with the regulatory process, the level of rates and revenues, and the ability to recover costs. Such uncertainty restricts flexibility and resources, given the need to plan and ensure available financial resources. Such uncertainty also affects the costs of doing business. Such costs could ultimately reduce liquidity, as suppliers tighten payment terms, and increase costs of financing, as lenders demand increased compensation or collateral security to accept such risks.

Our Profitability is Impacted by Our Affiliated Companies’ Continued Authorization to Sell Power at Market-Based Rates

The FERC granted FES, FGCO and NGC authority to sell electricity at market-based rates. These orders also granted them waivers of certain FERC accounting, record-keeping and reporting requirements. The Utilities also have market-based rate authority.  The FERC’s orders that grant this market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that these companies can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions. As a condition to the orders granting the generating companies market-based rate authority, every three years they are required to file a market power update to show that they continue to meet the FERC’s standards with respect to generation market power and other criteria used to evaluate whether entities qualify for market-based rates. FES, FGCO, NGC and the Utilities renewed this authority for PJM in 2008. Their applications to renew this authorization for MISO are pending at the FERC. If any of these companies were to lose their market-based rate authority or fail to have such authority renewed, it would be required to obtain the FERC’s acceptance to sell power at cost-based rates. FES, FGCO and NGC could also lose their waivers, and become subject to the accounting, record-keeping and reporting requirements that are imposed on utilities with cost-based rate schedules.

 

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There Are Uncertainties Relating to Our Participation in Regional Transmission Organizations (RTOs)

RTO rules could affect our ability to sell power produced by our generating facilities to users in certain markets due to transmission constraints and attendant congestion costs. The prices in day-ahead and real-time energy markets and RTO capacity markets have been subject to price volatility. Administrative costs imposed by RTOs, including the cost of administering energy markets, have also increased. The rules governing the various regional power markets may also change from time to time, which could affect our costs or revenues. To the degree we incur significant additional fees and increased costs to participate in an RTO, and we are limited with respect to recovery of such costs from retail customers, we may suffer financial harm. While RTO rates for transmission service are designed to be revenue neutral, our revenues from customers to whom we currently provide transmission services may not reflect all of the administrative and market-related costs imposed under the RTO tariff. In addition, we may be allocated a portion of the cost of transmission facilities built by others due to changes in RTO transmission rate design. Finally, we may be required to expand our transmission system according to decisions made by an RTO rather than our internal planning process. As a member of an RTO, we are subject to certain additional risks, including those associated with the allocation among members of losses caused by unreimbursed defaults of other participants in that RTO’s market, and those associated with complaint cases filed against the RTO that may seek refunds of revenues previously earned by its members.

MISO implemented an ancillary services market for operating reserves that would be simultaneously co-optimized with MISO's existing energy markets. The implementation of these and other new market designs has the potential to increase our costs of transmission, costs associated with inefficient generation dispatching, costs of participation in the market and costs associated with estimated payment settlements.

Because it remains unclear which companies will be participating in the various regional power markets, or how RTOs will ultimately develop and operate, or what region they will cover, we cannot fully assess the impact that these power markets or other ongoing RTO developments may have.

Energy Conservation and Energy Price Increases Could Negatively Impact our Financial Results

A number of regulatory and legislative bodies have introduced requirements and/or incentives to reduce energy consumption by certain dates. Conservation programs could impact our financial results in different ways. To the extent conservation resulted in reduced energy demand or significantly slowed the growth in demand, the value of our merchant generation and other unregulated business activities could be adversely impacted. In our regulated operations, conservation could negatively impact us depending on the regulatory treatment of the associated impacts. Should we be required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact. We could also be impacted if any future energy price increases result in a decrease in customer usage.  We are unable to determine what impact, if any, conservation and increases in energy prices will have on our financial condition or results of operations.

Our Business and Activities are Subject to Extensive Environmental Requirements and Could be Adversely Affected by such Requirements

We may be forced to shut down facilities, either temporarily or permanently, if we are unable to comply with certain environmental requirements, or if we make a determination that the expenditures required to comply with such requirements are uneconomical. In fact, we are exposed to the risk that such electric generating plants would not be permitted to continue to operate if pollution control equipment is not installed by prescribed deadlines.

Costs of Compliance with Environmental Laws are Significant, and the Cost of Compliance with Future Environmental Laws, Including Limitations on GHG   Emissions Could Adversely Affect Cash Flow and Profitability

Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations. Compliance with these legal requirements requires us to incur costs for environmental monitoring, installation of pollution control equipment, emission fees, maintenance, upgrading, remediation and permitting at our facilities. These expenditures have been significant in the past and may increase in the future. If the cost of compliance with existing environmental laws and regulations does increase, it could adversely affect our business and results of operations, financial position and cash flows. Moreover, changes in environmental laws or regulations may materially increase our costs of compliance or accelerate the timing of capital expenditures. Because of the deregulation of generation, we may not directly recover through rates additional costs incurred for such compliance. Our compliance strategy, although reasonably based on available information, may not successfully address future relevant standards and interpretations. If we fail to comply with environmental laws and regulations, even if caused by factors beyond our control or new interpretations of longstanding requirements, that failure could result in the assessment of civil or criminal liability and fines. In addition, any alleged violation of environmental laws and regulations may require us to expend significant resources to defend against any such alleged violations.

 

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There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. Environmental advocacy groups, other organizations and some agencies in the United States are focusing considerable attention on carbon dioxide emissions from power generation facilities and their potential role in climate change.  Many states and environmental groups have also challenged certain of the federal laws and regulations relating to air emissions as not being sufficiently strict.  There is a growing consensus in the United States and globally that GHG emissions are a major cause of global warming and that some form of regulation will be forthcoming at the federal level with respect to GHG emissions (including carbon dioxide) and such regulation could result in the creation of substantial additional costs in the form of taxes or emission allowances.  As a result, it is possible that state and federal regulations will be developed that will impose more stringent limitations on emissions than are currently in effect. Although several bills have been introduced at the state and federal level that would compel carbon dioxide emission reductions, none have advanced through the legislature. Such legislation could even make some of our electric generating units uneconomic to maintain or operate. Due to the uncertainty of control technologies available to reduce greenhouse gas emissions including  CO 2 , as well as the unknown nature of potential compliance obligations should climate change regulations be enacted, we cannot provide any assurance regarding the potential impacts these future regulations would have on our operations. In addition, any legal obligation that would require us to substantially reduce our emissions could require extensive mitigation efforts and, in the case of carbon dioxide legislation, would raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities. Until specific regulations are promulgated, the impact that any new environmental regulations, voluntary compliance guidelines, enforcement initiatives, or legislation may have on our results of operations, financial condition or liquidity is not determinable.

The EPA’s current CAIR and CAVR require significant reductions beginning in 2009 in air emissions from coal-fired power plants and the states have been given substantial discretion in developing their own rules to implement these programs. On December 23, 2008, the United States Court of Appeals for the District of Columbia remanded CAIR to EPA but allowed the current CAIR regulations to remain in effect while EPA works to remedy flaws in the CAIR regulations identified by the court in a July 11, 2008 opinion. As a result, the ultimate requirements under CAIR may not be known for several years and may differ significantly from the current CAIR regulations. If the EPA significantly changes CAIR, or if the states elect to impose additional requirements on individual units that are already subject to CAIR, the cost of compliance could increase significantly and could have an adverse effect on future results of operations, cash flows and financial condition.

The EPA's final CAMR was vacated by the United States Court of Appeals for the District Court of Columbia on February 8, 2008 because the EPA failed to take the necessary steps to "de-list" coal-fired power plants from its hazardous air pollution program and therefore could not promulgate a cap and trade air emissions reduction program.  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 United States moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the United States’ petition and denied the industry group’s petition. Accordingly, the EPA could take regulatory action to promulgate new mercury emission standards for coal-fired power plants. As a result of further regulatory action by the EPA, the cost of compliance could increase significantly and could have a material adverse effect on future results of operations, cash flows and financial condition.

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

There is substantial uncertainty concerning the final form of federal and state regulations to implement Section 316(b) of the Clean Water Act.  On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded back to the EPA portions of its rulemaking pursuant to Section 316(b). The EPA subsequently suspended its rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 14, 2008, the Supreme Court of the United States granted a petition for a writ of certiorari to review one significant aspect of the Second Circuit Court’s decision.  Oral argument before the Supreme Court occurred on December 2, 2008 and a decision is anticipated during the first half of 2009.  Depending on the outcome of the Supreme Court’s review and the nature of the final regulations that may ultimately be adopted by the EPA, we may incur significant capital costs to comply with the final regulations.  If either the federal or state final regulations require retrofitting of cooling water intake structures (cooling towers) at any of our power plants, and if installation of such cooling towers is not technically or economically feasible, we may be forced to take actions which could adversely impact our results of operations and financial condition.

 

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Remediation of Environmental Contamination at Current or Formerly Owned Facilities

 

We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we may have generated regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities. Remediation activities associated with our former MGP operations are one source of such costs. We are currently involved in a number of proceedings relating to sites where other hazardous substances have been deposited and may be subject to additional proceedings in the future. We also have current or previous ownership interests in sites associated with the production of gas and the production and delivery of electricity for which we may be liable for additional costs related to investigation, remediation and monitoring of these sites. Citizen groups or others may bring litigation over environmental issues including claims of various types, such as property damage, personal injury, and citizen challenges to compliance decisions on the enforcement of environmental requirements, such as opacity and other air quality standards, which could subject us to penalties, injunctive relief and the cost of litigation. We cannot predict the amount and timing of all future expenditures (including the potential or magnitude of fines or penalties) related to such environmental matters, although we expect that they could be material.

 

In some cases, a third party who has acquired assets from us has assumed the liability we may otherwise have for environmental matters related to the transferred property. If the transferee fails to discharge the assumed liability or disputes its responsibility, a regulatory authority or injured person could attempt to hold us responsible, and our remedies against the transferee may be limited by the financial resources of the transferee.

Availability and Cost of Emission Credits Could Materially Impact Our Costs of Operations

 

We are required to maintain, either by allocation or purchase, sufficient emission credits to support our operations in the ordinary course of operating our power generation facilities. These credits are used to meet our obligations imposed by various applicable environmental laws. If our operational needs require more than our allocated allowances of emission credits, we may be forced to purchase such credits on the open market, which could be costly. If we are unable to maintain sufficient emission credits to match our operational needs, we may have to curtail our operations so as not to exceed our available emission credits, or install costly new emissions controls. As we use the emissions credits that we have purchased on the open market, costs associated with such purchases will be recognized as operating expense. If such credits are available for purchase, but only at significantly higher prices, the purchase of such credits could materially increase our costs of operations in the affected markets.

Mandatory Renewable Portfolio Requirements Could Negatively Affect Our Costs

If federal or state legislation mandates the use of renewable and alternative fuel sources, such as wind, solar, biomass and geothermal, and such legislation would not also provide for adequate cost recovery, it could result in significant changes in our business, including renewable energy credit purchase costs, purchased power and potentially renewable energy credit costs and capital expenditures.  We are unable to predict what impact, if any, these changes may have on our financial condition or results of operations.

We Are and May Become Subject to Legal Claims Arising from the Presence of Asbestos or Other Regulated Substances at Some of our Facilities

We have been named as a defendant in pending asbestos litigation involving multiple plaintiffs and multiple defendants. In addition, asbestos and other regulated substances are, and may continue to be, present at our facilities where suitable alternative materials are not available. We believe that any remaining asbestos at our facilities is contained. The continued presence of asbestos and other regulated substances at these facilities, however, could result in additional actions being brought against us.

The Continuing Availability and Operation of Generating Units is Dependent on Retaining the Necessary Licenses, Permits, and Operating Authority from Governmental Entities, Including the NRC

 

We are required to have numerous permits, approvals and certificates from the agencies that regulate our business. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from future regulatory activities of any of these agencies and we are not assured that any such permits, approvals or certifications will be renewed.

 

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Future Changes in Financial Accounting Standards May Affect Our Reported Financial Results

The SEC, FASB or other authoritative bodies or governmental entities may issue new pronouncements or new interpretations of existing accounting standards that may require us to change our accounting policies. These changes are beyond our control, can be difficult to predict and could materially impact how we report our financial condition and results of operations. We could be required to apply a new or revised standard retroactively, which could adversely affect our financial position. The SEC has issued a roadmap for the transition by U.S. public companies to the use of International Financial Reporting Standards (IFRS) promulgated by the International Accounting Standards Board. Under the SEC’s proposed roadmap, we could be required in 2014 to prepare financial statements in accordance with IFRS. The SEC expects to make a determination in 2011 regarding the mandatory adoption of IFRS. We are currently assessing the impact that this potential change would have on our consolidated financial statements and we will continue to monitor the development of the potential implementation of IFRS.

Risks Associated With Financing and Capital Structure

Interest Rates and/or a Credit Rating Downgrade Could Negatively Affect Our Financing Costs, Our Ability to Access Capital and Our Requirement to Post Collateral

 

We have near-term exposure to interest rates from outstanding indebtedness indexed to variable interest rates, and we have exposure to future interest rates to the extent we seek to raise debt in the capital markets to meet maturing debt obligations and fund construction or other investment opportunities. The recent disruptions in capital and credit markets have resulted in higher interest rates on new publicly issued debt securities, increased costs for certain of our variable interest rate debt securities and failed remarketings (all of which were eventually remarketed) of variable interest rate tax-exempt debt issued to finance certain of our facilities. Continuation of these disruptions could increase our financing costs and adversely affect our results of operations. Also, interest rates could change as a result of economic or other events that our risk management processes were not established to address. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events lead to greater losses or costs than our risk management positions were intended to hedge. Although we employ risk management techniques to hedge against interest rate volatility, significant and sustained increases in market interest rates could materially increase our financing costs and negatively impact our reported results of operations.

We rely on access to bank and capital markets as sources of liquidity for cash requirements not satisfied by cash from operations. A downgrade in our credit ratings from the nationally recognized credit rating agencies, particularly to a level below investment grade, could negatively affect our ability to access the bank and capital markets, especially in a time of uncertainty in either of those markets, and may require us to post cash collateral to support outstanding commodity positions in the wholesale market, as well as available letters of credit and other guarantees. A rating downgrade would also increase the fees we pay on our various credit facilities, thus increasing the cost of our working capital. A rating downgrade could also impact our ability to grow our businesses by substantially increasing the cost of, or limiting access to, capital. Our senior unsecured debt ratings from S&P and Moody’s are investment grade. The current ratings outlook from S&P and Moody’s is stable.

A rating is not a recommendation to buy, sell or hold debt, inasmuch as such rating does not comment as to market price or suitability for a particular investor. The ratings assigned to our debt address the likelihood of payment of principal and interest pursuant to their terms. A rating may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating that may be assigned to our securities.  Also, we cannot predict how rating agencies may modify their evaluation process or the impact such a modification may have on our ratings.

Our credit ratings also govern the collateral provisions of certain contract guarantees. Subsequent to the occurrence of a credit rating downgrade to below investment grade or a “material adverse event,” the immediate posting of cash collateral may be required. See Note 14(B) of the Notes to the Consolidated Financial Statements for more information associated with a credit ratings downgrade leading to the posting of cash collateral.

We Must Rely on Cash from Our Subsidiaries and Any Restrictions on Our Utility Subsidiaries’ Ability to Pay Dividends or Make Cash Payments to Us May Adversely Affect Our Financial Condition

We are a holding company and our investments in our subsidiaries are our primary assets. Substantially all of our business is conducted by our subsidiaries. Consequently, our cash flow is dependent on the operating cash flows of our subsidiaries and their ability to upstream cash to the holding company. Our utility subsidiaries are regulated by various state utility commissions that generally possess broad powers to ensure that the needs of utility customers are being met. Those state commissions could attempt to impose restrictions on the ability of our utility subsidiaries to pay dividends or otherwise restrict cash payments to us.

 

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We Cannot Assure Common Shareholders that Future Dividend Payments Will be Made, or if Made, in What Amounts they May be Paid

Our Board of Directors regularly evaluates our common stock dividend policy and determines the dividend rate each quarter. The level of dividends will continue to be influenced by many factors, including, among other things, our earnings, financial condition and cash flows from subsidiaries, as well as general economic and competitive conditions. We cannot assure common shareholders that dividends will be paid in the future, or that, if paid, dividends will be at the same amount or with the same frequency as in the past.

 

Disruptions in the Capital and Credit Markets May Adversely Affect our Business, Including the Availability and Cost of Short-Term Funds for Liquidity Requirements, Our Ability to Meet Long-Term Commitments, our Ability to Hedge Effectively our Generation Portfolio, and the Competitiveness and Liquidity of Energy Markets; Each Could Adversely Affect our Results of Operations, Cash Flows and Financial Condition

 

We rely on the capital markets to meet our financial commitments and short-term liquidity needs if internal funds are not available from our operations. We also use letters of credit provided by various financial institutions to support our hedging operations. Disruptions in the capital and credit markets, as have been experienced during 2008, could adversely affect our ability to draw on our respective credit facilities. Our access to funds under those credit facilities is dependent on the ability of the financial institutions that are parties to the facilities to meet their funding commitments. Those institutions may not be able to meet their funding commitments if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time.

 

Longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could adversely affect our access to liquidity needed for our business. Any disruption could require us to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures, changing hedging strategies to reduce collateral-posting requirements, and reducing or eliminating future dividend payments or other discretionary uses of cash.

 

The strength and depth of competition in energy markets depends heavily on active participation by multiple counterparties, which could be adversely affected by disruptions in the capital and credit markets. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to our business. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace those market structures with other mechanisms for the sale of power, including the requirement of long-term contracts, which could have a material adverse effect on our results of operations and cash flows.

Questions Regarding the Soundness of Financial Institutions or Counterparties Could Adversely Affect Us

We have exposure to many different financial institutions and counterparties and we routinely execute transactions with counterparties in connection with our hedging activities, including brokers and dealers, commercial banks, investment banks and other institutions and industry participants. Many of these transactions expose us to credit risk in the event that any of our lenders or counterparties are unable to honor their commitments or otherwise default under a financing agreement. We also deposit cash balances in short-term investments.  Our ability to access our cash quickly depends on the soundness of the financial institutions in which those funds reside.  Any delay in our ability to access those funds, even for a short period of time, could have a material adverse effect on our results of operations and financial condition.

Our Electric Utility Operating Affiliates in Ohio are Currently in the Midst of Rate Proceedings that have the Potential to Adversely Affect Our Financial Condition  

As required by Amended Substitute Senate Bill 221 (SB221), Ohio ’s new electricity restructuring law, our Ohio utility subsidiaries filed on July 31, 2008 with the PUCO a comprehensive ESP and a n MRO. The ESP proposed, among other things, to phase in new generation rates for customers beginning in 2009 for up to a three-year period and to resolve a then pending distribution rate increase request. The MRO filing outlined a competitive bid process for providing retail generation supply at market prices in accordance with SB221 if the ESP was not approved and implemented by our Ohio utilities. The PUCO rejected the MRO filing on November 25, 2008 and we filed an application for rehearing on December 22, 2008.

 

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The PUCO modified the ESP on December 19, 2008. We withdrew the ESP as so modified on December 22, 2008 opting instead to keep the current rate plan in effect, as we believe SB221 requires. Because our Ohio utilities do not own generating plants, they subsequently completed a competitive procurement process to ensure a reliable supply of electricity, for customers who do not shop, for the period January 5, 2009 through March 31, 2009.

 

Subsequent to the competitive procurement process, the PUCO ruled that our Ohio utilities could not continue certain portions of their existing tariffs. Citing inconsistencies with Ohio law and potentially serious financial consequences that could result from the PUCO’s ruling, on January 9, 2009, we filed a motion to stay, as well as an application for rehearing and an application for a fuel rider. On January 9, 2009, an order was entered permitting our Ohio utilities to continue charging current rates until the PUCO rules on the pending filings. On January 14, 2009, the PUCO approved our Ohio utilities’ application to recover fuel and associated purchased power costs during the period January 1, 2009 through March 31, 2009 subject to review by the PUCO, and affirmed its January 9, 2009 order regarding our Ohio utilities’ ability to continue charging specific components of current rates.

Substantial recovery under the fuel rider is necessary to ensure that our Ohio utilities recover costs related to their provider-of-last-resort obligation to their customers. Without such recovery, providing generation service to their customers at rates that are well below actual costs would cause them to incur a cash shortfall of approximately $2 million per day. This could require our Ohio Utilities to make immediate and severe reductions in operating and capital expenditures and could have other material adverse impacts on the financial condition and results of operations of not only our Ohio utilities but also FirstEnergy. Any resulting deterioration in our financial metrics could result in a downgrade of our credit ratings.   On January 21, 2009, the PUCO granted our Ohio utilities’ application for an increase in distribution rates in the amount of $136.6 million in the aggregate for all three companies, as well as the application for rehearing of the MRO filing.

On February 19, 2009, the Ohio Companies filed an application for an amended ESP which substantially reflected the terms proposed by PUCO Staff to resolve the ESP proceeding, which the PUCO attorney examiner set for a hearing to begin on February 25, 2009 (see Regulatory Matters – Ohio).

ITEM 1B.   UNRESOLVED STAFF COMMENTS

None.

ITEM 2.      PROPERTIES

The Utilities’ and FGCO’s respective first mortgage indentures constitute, in the opinion of their counsel, direct first liens on substantially all of the respective Utilities’ and FGCO’s physical property, subject only to excepted encumbrances, as defined in the first mortgage indentures. See the “Leases” and “Capitalization” notes to the respective financial statements for information concerning leases and financing encumbrances affecting certain of the Utilities’ and FGCO’s properties.

FirstEnergy has access, either through ownership or lease, to the following generation sources as of February 25, 2009, shown in the table below. Except for the leasehold interests and OVEC participation referenced in the footnotes to the table, substantially all of the generating units are owned by NGC (nuclear) and FGCO (non-nuclear). See "Generation Asset Transfers" under Item 1 above.

 

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						Net
						Demonstrated
						Capacity
		Unit				(MW)
Plant-Location
Coal-Fired Units
Ashtabula-
Ashtabula, OH			5				244
Bay Shore-
Toledo, OH			1-4				631
R. E. Burger-
Shadyside, OH			3-5				406
Eastlake-Eastlake, OH			1-5				1,233
Lakeshore-
Cleveland, OH			18				245
Bruce Mansfield-			1				830	(a)
Shippingport, PA			2				830	(b)
			3				830	(c)
W. H. Sammis - Stratton, OH			1-7				2,220
Kyger Creek - Cheshire, OH			1-5				210	(d)
Clifty Creek - Madison, IN			1-6				253	(d)
Total							7,932
Nuclear Units
Beaver Valley-			1				911
Shippingport, PA			2				904	(e)
Davis-Besse-
Oak Harbor, OH			1				908
Perry-
N. Perry Village, OH			1				1,268	(f)
Total							3,991
Oil/Gas - Fired/
Pumped Storage Units
Richland - Defiance, OH			1-6				432
Seneca - Warren, PA			1-3				451
Sumpter - Sumpter Twp, MI			1-4				340
West Lorain - Lorain, OH			1-6				545
Yard’s Creek - Blairstown
Twp., NJ			1-3				200	(g)
Other							282
Total							2,250
Total							14,173

Notes:	(a)	Includes FGCO’s leasehold interest of 93.825% (779 MW) and CEI’s leasehold interest of 6.175% (51 MW), which has been assigned to FGCO.
	(b)	Includes CEI’s and TE’s leasehold interests of 27.17% (226 MW) and 16.435% (136 MW), respectively, which have been assigned to FGCO.
	(c)	Includes CEI’s and TE’s leasehold interests of 23.247% (193 MW) and 18.915% (157 MW), respectively, which have been assigned to FGCO.
	(d)	Represents FGCO’s 20.5% entitlement based on its participation in OVEC. FGCO has entered into a definitive agreement to sell 9% of its 20.5% participation in OVEC.  Final closing of the transaction, which is expected in April 2009, is subject to approval by the FERC.
	(e)	Includes OE’s leasehold interest of 16.65% (151 MW) from non-affiliates.
	(f)	Includes OE’s leasehold interest of 8.11% (103 MW) from non-affiliates.
	(g)	Represents JCP&L’s 50% ownership interest.

The above generating plants and load centers are connected by a transmission system consisting of elements having various voltage ratings ranging from 23 kV to 500 kV. The Utilities’ overhead and underground transmission lines aggregate 15,070 pole miles.

 

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The Utilities’ electric distribution systems include 118,562 miles of overhead pole line and underground conduit carrying primary, secondary and street lighting circuits. They own substations with a total installed transformer capacity of 87,624,000 kV-amperes.

The transmission facilities that are owned by ATSI are operated on an integrated basis as part of MISO and are interconnected with facilities operated by PJM. The transmission facilities of JCP&L, Met-Ed and Penelec are physically interconnected and are operated on an integrated basis as part of PJM.

FirstEnergy’s distribution and transmission systems as of December 31, 2008, consist of the following:

										Substation
		Distribution				Transmission				Transformer
		Lines				Lines				Capacity
		(Miles)								(kV-amperes)
OE			30,413				555				9,718,000
Penn			5,911				44				922,000
CEI			25,321				2,144				7,841,000
TE			2,083				224				2,503,000
JCP&L			19,604				2,160				21,216,000
Met-Ed			15,057				1,421				9,962,000
Penelec			20,173				2,701				14,033,000
ATSI*			-				5,821				21,429,000
Total			118,562				15,070				87,624,000

*

Represents transmission lines of 69kV and above located in the service areas of OE, Penn, CEI and TE.

ITEM 3.      LEGAL PROCEEDINGS

Reference is made to Note 14, Commitments, Guarantees and Contingencies, of FirstEnergy’s Notes to Consolidated Financial Statements contained in Item 8 for a description of certain legal proceedings involving FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec.

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

None.

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The information required by Item 5 regarding FirstEnergy’s market information, including stock exchange listings and quarterly stock market prices, dividends and holders of common stock is included on page 1 of FirstEnergy’s 2008 Annual Report to Stockholders (Exhibit 13.1). Pursuant to General Instruction I of Form 10-K, information for FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec is not required to be disclosed because they are wholly owned subsidiaries.

Information regarding compensation plans for which shares of FirstEnergy common stock may be issued is incorporated herein by reference to FirstEnergy’s 2009 proxy statement filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.

 

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The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock during the fourth quarter of 2008.

		Period
		October				November				December				Fourth Quarter
Total Number of Shares Purchased (a)			22,317				44,129				253,936				320,382
Average Price Paid per Share		$	54.66			$	54.39			$	55.94			$	55.64
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, and shares purchased as part of publicly announced plans.

ITEM 6.      SELECTED FINANCIAL DATA

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 8.       FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by Items 6 through 8 is incorporated herein by reference to Selected Financial Data, Management’s Discussion and Analysis of Financial Condition and Results of Operation, and Financial Statements included on the following pages in the 2008 Annual Report of FirstEnergy (Exhibit 13.1) and the combined 2008 Annual Report of FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec (Exhibit 13.2).

	Item 6*	Item 7*	Item 7A	Item 8
FirstEnergy	1-2	3-59	38-41	62-109
FES	N/A	N/A	3-5	8-12, 91-145
OE	N/A	N/A	14-15	18-22, 91-145
CEI	N/A	N/A	24-25	28-32, 91-145
TE	N/A	N/A	35	38-42, 91-145
JCP&L	N/A	N/A	44-46	49-53, 91-145
Met-Ed	N/A	N/A	55-57	60-64, 91-145
Penelec	N/A	N/A	66-68	71-75, 91-145

*FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to Form 10-K.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.   CONTROLS AND PROCEDURES -- FIRSTENERGY

Evaluation of Disclosure Controls and Procedures

FirstEnergy's Chief Executive Officer and Chief Financial Officer have reviewed and evaluated such registrant’s disclosure controls and procedures, as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e), as of the end date covered by this report. Based upon this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that FirstEnergy's disclosure controls and procedures were effective as of December 31, 2008.

 

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Management’s Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework, management conducted an evaluation of the effectiveness of FirstEnergy's internal control over financial reporting under the supervision of FirstEnergy's Chief Executive Officer and Chief Financial Officer. Based on that evaluation, management concluded that FirstEnergy's internal control over financial reporting was effective as of December 31, 2008. The effectiveness of FirstEnergy's internal control over financial reporting, as of December 31, 2008, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report included in FirstEnergy's 2008 Annual Report to Stockholders and incorporated by reference hereto.

Changes in Internal Control over Financial Reporting

There were no changes in FirstEnergy's internal control over financial reporting during the fourth quarter of 2008 that have materially affected, or are reasonably likely to materially affect, FirstEnergy's internal control over financial reporting.

ITEM 9A(T). CONTROLS AND PROCEDURES -- FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec

Evaluation of Disclosure Controls and Procedures

Each registrant's Chief Executive Officer and Chief Financial Officer have reviewed and evaluated such registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934 rules 13a-15(e) and 15d-15(e), as of the end date covered by this report. Based upon this evaluation, the respective Chief Executive Officer and Chief Financial Officer concluded that such registrant's disclosure controls and procedures were effective as of December 31, 2008.

Management’s Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework, management conducted an evaluation of the effectiveness of each registrant’s internal control over financial reporting under the supervision of such registrant’s Chief Executive Officer and Chief Financial Officer. Based on that evaluation, management concluded that each registrant’s internal control over financial reporting was effective as of December 31, 2008. The effectiveness of each registrant's internal control over financial reporting, as of December 31, 2008, has not been audited by such registrant’s independent registered public accounting firm.

Changes in Internal Control over Financial Reporting

Related to the remediation of the material weakness described below, there were changes in internal control over financial reporting during the fourth quarter of 2008 for OE, CEI, TE and Penelec. During the fourth quarter of 2008, management of OE, CEI, TE and Penelec identified a material weakness in their accounting for unpaid dividends to FirstEnergy. This material weakness was attributable to an inadequate control to ensure that declared but unpaid dividends to FirstEnergy were not reported as cash used for financing activities on the Consolidated Statement of Cash Flows for each of the affected registrants. As a result of this material weakness, OE, CEI, TE and Penelec restated their Consolidated Statements of Cash Flows for the year ended December 31, 2007, the three months ended March 31, 2008, the six months ended June 30, 2008 and the nine months ended September 30, 2008. The Consolidated Statements of Income and Consolidated Balance Sheets were not affected by the error. In an effort to remediate the identified material weakness, management of OE, CEI, TE and Penelec has implemented a process to segregate dividend declarations with payments applicable to future reporting periods in a unique general ledger account in order to distinguish associated company dividends payable from other associated company accounts payable. Management believes that this process is fully functional, enhances the existing internal control over financial reporting and, prior to the end of the period covered by this report, remediated the material weakness in the internal controls related to the preparation and review of the Consolidated Statements of Cash Flows, which was identified in the fourth quarter of 2008.

There were no changes in internal control over financial reporting during the fourth quarter of 2008 that have materially affected, or are reasonably likely to materially affect, internal control over financial reporting for FES, JCP&L and Met-Ed.

ITEM 9B.   OTHER INFORMATION

None.

 

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PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by Item 10, with respect to identification of FirstEnergy’s directors and with respect to reports required to be filed under Section 16 of the Securities Exchange Act of 1934, is incorporated herein by reference to FirstEnergy’s 2009 Proxy Statement filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934 and, with respect to identification of executive officers, to “Part I, Item 1. Business – Executive Officers” herein.

The Board of Directors, upon recommendation of the Corporate Governance and Audit Committees, has determined that Ernest J. Novak, Jr., an independent director, is the audit committee financial expert.

FirstEnergy makes available on its Web site at http://www.firstenergycorp.com/ir its Corporate Governance Policies and the charters for each of the following committees of the Board of Directors: Audit; Corporate Governance; Compensation; Finance; and Nuclear. The Corporate Governance Policies and Board committee charters are also available in print upon written request to Rhonda S. Ferguson, Corporate Secretary, FirstEnergy Corp., 76 South Main Street, Akron, OH 44308-1890.

FirstEnergy has adopted a Code of Business Conduct, which applies to all employees, including the Chief Executive Officer, the Chief Financial Officer and the Chief Accounting Officer. In addition, the Board of Directors has its own Code of Business Conduct. These Codes can be found on the Web site provided in the previous paragraph or upon written request to the Corporate Secretary.

Pursuant to Section 303A.12(a) of the New York Stock Exchange Listed Company Manual, the Company submitted the Annual CEO Certification to the NYSE on May 23, 2008.

ITEM 11.

EXECUTIVE COMPENSATION

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by Items 11, 12 and 13 is incorporated herein by reference to FirstEnergy’s 2009 Proxy Statement filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.

ITEM 14.    PRINCIPAL ACCOUNTING FEES AND SERVICES

A summary of the audit and audit-related fees rendered by PricewaterhouseCoopers LLP for the years ended December 31, 2008 and 2007 are as follows:

		Audit Fees (1)								Audit-Related Fees
Company		200 8				200 7				200 8				200 7
		(In thousands)
FES		$	835			$	1,091			$	-			$	494
OE			1,155				1,014				-				-
CEI			764				719				-				-
TE			598				540				-				-
JCP&L			682				701				-				-
Met-Ed			583				528				-				-
Penelec			595				586				-				-
Other subsidiaries			607				886				-				-
Total FirstEnergy		$	5,819			$	6,065			$	-			$	494

 

(1)

Professional services rendered for the audits of FirstEnergy’s annual financial statements and reviews of financial statements included in FirstEnergy’s Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.

 

Tax and Other Fees

 

There were no other fees billed to FirstEnergy for tax or other services for the years ended December 31, 2008 and 2007.

Additional information required by this item is incorporated herein by reference to FirstEnergy's 2009 Proxy Statement filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.

 

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PART IV

ITEM 15.    EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)

1.     Financial Statements

Included in Part II of this report and incorporated herein by reference to the 2008 Annual Report of FirstEnergy (Exhibit 13.1) and the combined 2008 Annual Report of FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec (Exhibit 13.2) at the pages indicated.

	FirstEnergy	FES	OE	CEI	TE	JCP&L	Met-Ed	Penelec
Management Reports	59	6	16	26	36	47	58	69
Report of Independent Registered Public Accounting Firm	60	7	17	27	37	48	59	70
Statements of Income, Three Years Ended December 31, 2008	61	8	18	28	38	49	60	71
Balance Sheets, December 31, 2008 and 2007	62	9	19	29	39	50	61	72
Statements of Capitalization, December 31, 2008 and 2007	N/A	10	20	30	40	51	62	73
Statements of Common Stockholders’ Equity, Three Years Ended December 31, 2008	63	11	21	31	41	52	63	74
Statements of Cash Flows, Three Years Ended December 31, 2008	64	12	22	32	42	53	64	75
Notes to Financial Statements	65-108	91-145	91-145	91-145	91-145	91-145	91-145	91-145

2.	Financial Statement Schedules

Included in Part IV of this report:

	FirstEnergy	FES	OE	CEI	TE	JCP&L	Met-Ed	Penelec
Report of Independent Registered Public Accounting Firm	73	74	75	76	77	78	79	80
Schedule II -- Consolidated Valuation and Qualifying Accounts, Three Years Ended December 31, 2008	81	82	83	84	85	86	87	88

Schedules other than the schedule listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the financial statements or notes thereto.

3.	Exhibits – FirstEnergy

Exhibit

Number