Form 10-K Dated Decemer 31, 2005
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K

(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2005
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________________ to ___________________

Commission
Registrant; State of Incorporation;
I.R.S. Employer
File Number
Address; and Telephone Number
Identification No.
     
333-21011
FIRSTENERGY CORP.
34-1843785
 
(An Ohio Corporation)
 
 
76 South Main Street
 
 
Akron, OH 44308
 
 
Telephone (800)736-3402
 
     
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
 
     
1-3491
PENNSYLVANIA POWER COMPANY
25-0718810
 
(A Pennsylvania 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
         
Ohio Edison Company
 
Cumulative Preferred Stock, $100 par value:
   
   
3.90% Series
 
All series registered on New
   
4.40% Series
 
York Stock Exchange and
   
4.44% Series
 
Chicago Stock Exchange
   
4.56% Series
   
         
         
The Toledo Edison
 
Cumulative Preferred Stock, par value
   
Company
 
$100 per share:
   
   
4-1/4% Series
 
American Stock Exchange
         
   
Cumulative Preferred Stock, par value
   
   
$25 per share:
   
   
$2.365 Series
 
All series registered on
       
New York Stock Exchange
   
        Adjustable Rate, Series B
   
         
         
Jersey Central Power &
 
Cumulative Preferred Stock, without
   
Light Company
 
par value:
   
   
4% Series
 
New York Stock Exchange
 

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

     
Registrant
 
Title of Each Class
     
Pennsylvania Power Company
 
Cumulative Preferred Stock, $100 par value;
   
4.24% Series
   
4.25% Series
   
4.64% Series
 
 

 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes (X) No ( )
Metropolitan Edison Company and Pennsylvania Electric Company
Yes ( ) No (X)
FirstEnergy Corp., Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company and Jersey Central Power & Light Company
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days: Yes (X) No (  )

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

(X)
FirstEnergy Corp.
( )
Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company.
 
           Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer
 (X)
FirstEnergy Corp.
Accelerated Filer
( )
N/A
Non-accelerated
Filer
 (X)
Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yes ( ) No (X)

State the aggregate market value of the common stock held by non-affiliates of the registrants: FirstEnergy Corp., $15,814,415,770 as of June 30, 2005; and for all other registrants, none.

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

   
OUTSTANDING
CLASS
 
As of March 1, 2006
     
FirstEnergy Corp., $0.10 par value
 
329,836,276
Ohio Edison Company, no par value
 
100
The Cleveland Electric Illuminating Company, no par value
 
79,590,689
The Toledo Edison Company, $5 par value
 
39,133,887
Pennsylvania Power Company, $30 par value
 
6,290,000
Jersey Central Power & Light Company, $10 par value
 
15,371,270
Metropolitan Edison Company, no par value
 
859,500
Pennsylvania Electric Company, $20 par value
 
5,290,596

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


 
Documents incorporated by reference (to the extent indicated herein):
 
   
PART OF FORM 10-K INTO WHICH
DOCUMENT
 
DOCUMENT IS INCORPORATED
     
FirstEnergy Corp. Annual Report to Stockholders for
   
the fiscal year ended December 31, 2005 (Pages 3-94)
 
Part II
     
Proxy Statement for 2006 Annual Meeting of Stockholders
   
to be held May 16, 2006
 
Part III

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

 
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
Companies
OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec 
FENOC
FirstEnergy Nuclear Operating Company, operates nuclear generating facilities
FES
FirstEnergy Solutions Corp., provides energy-related products and services
FESC
FirstEnergy Service Company, provides legal, financial, and other corporate support services
FGCO
FirstEnergy Generation Corp., owns and operates nonnuclear generating facilities
FirstEnergy
FirstEnergy Corp., a registered public utility holding company
FSG
FirstEnergy Facilities Services Group, LLC, the parent company of several heating,
ventilation, air conditioning and energy management companies
GPU
GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on
November 7, 2001
JCP&L
Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
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
Shippingport
Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
TE
The Toledo Edison Company, an Ohio electric utility operating subsidiary
   
The following abbreviations and acronyms are used to identify frequently used terms in this report:
   
AEP
American Electric Power Company, Inc.
ALJ
Administrative Law Judge
BGS
Basic Generation Service
CAIR
Clean Air Interstate Rule
CAL
Confirmatory Action Letter
CAMR
Clean Air Mercury Rule
CAVR
Clean Air Visibility Rule
CO2 Carbon Dioxide
CTC
Competitive Transition Charge
DOJ
United States Department of Justice
DPL
Dayton Power & Light Company
DRA
Division of the Rate Payer Advocate
ECAR
East Central Area Reliability Coordination Agreement
EPA
Environmental Protection Agency only in various other terms
EPACT
Energy Policy Act of 2005
ERO
Electric Reliability Organization
FASB
Financial Accounting Standards Board
FEPA
Federal Environmental Protection Agency
FERC
Federal Energy Regulatory Commission
FIN
FASB Interpretation
FIN 46
FIN 46 “Consolidation of Variable Interest Entities”
FMB
First Mortgage Bonds
GCAF
Generation Charge Adjustment Factor
GHG
Greenhouse Gases
HVAC
Heating, Ventilation and Air-conditioning
MEC
Michigan Electric Coordination Systems
MEIUG
Met-Ed Industrial Users Group
MISO
Midwest Independent Transmission System Operator, Inc.
Moody's
Moody's Investors Service
MOU
Memorandum of Understanding
MTC
Market Transition Charge
MW
Megawatts


i

GLOSSARY OF TERMS Cont'd.


NAAQS
National Ambient Air Quality Standards
NERC
North American Electric Reliability Council
NEIL
Nuclear Electric Insurance Limited
NJBPU
New Jersey Board of Public Utilities
NOAC
Northwest Ohio Aggregation Coalition
NOV
Notices of Violation
NOx Nitrogen Oxide
NRC
Nuclear Regulatory Commission
NUG
Non-Utility Generator
NYSE
New York Stock Exchange
OAL
Office of Administrative Law
OCA
Office of Consumer Advocate
OCC
Ohio Consumers’ Counsel
OPAE
Ohio Partners of Affordable Energy
OSBA
Office of Small Business Advocate
OTS
Office of Trial Staff
PICA
Penelec Industrial Customer Association
PJM
PJM Interconnection L.L.C.
PLR
Provider of Last Resort
PPUC
Pennsylvania Public Utility Commission
PRP
Potentially Responsible Party
PUCO
Public Utilities Commission of Ohio
PUHCA
Public Utility Holding Company Act of 1935
RCP
Rate Certainty Plan
RFP         Request For Proposal
RSP
Rate Stabilization Plan
RTC
Regulatory Transition Charge
RTO
Regional Transmission Organization
S&P
Standard & Poor’s Ratings Service
SBC
Societal Benefits Charge
SEC
U.S. Securities and Exchange Commission
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”
SO2
Sulfur Dioxide
TMI-1
Three Mile Island Unit 1
TMI-2
Three Mile Island Unit 2
 

ii

 


FORM 10-K
TABLE OF CONTENTS
 
Page
Part I
 
Item 1. Business
1
The Company
1
Generation Asset Transfers
2
Divestitures
2
Utility Regulation
3
Regulatory Accounting
3
Reliability Initiatives
4
PUCO Rate Matters
5
PPUC Rate Matters
6
NJBPU Rate Matters
7
FERC Rate Matters
9
Capital Requirements
9
Nuclear Regulation
11
Nuclear Insurance
12
Environmental Matters
13
Clean Air Act Compliance
13
National Ambient Air Quality Standards
14
Mercury Emissions
14
W. H. Sammis Plant
15
Climate Change
15
Clean Water Act
15
Regulation of Hazardous Waste
15
Fuel Supply
15
System Capacity and Reserves
16
Regional Reliability
16
Competition
17
Research and Development
17
Executive Officers
17
Employees
19
FirstEnergy Website
19
   
Item 1A. Risk Factors
19
   
Item 1B. Unresolved Staff Comments
24
   
Item 2. Properties
24
   
Item 3. Legal Proceedings
26
   
Item 4. Submission of Matters to a Vote of Security Holders
26
   
Part II
 
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities
26
   
Item 6. Selected Financial Data
27
   
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
27
   
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
27
   
Item 8. Financial Statements and Supplementary Data
27
   
Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
27
   
Item 9A. Controls and Procedures
27
   
Item 9B. Other Information
29
   
Part III
 
Item 10. Directors and Executive Officers of the Registrant
29
   
Item 11. Executive Compensation
30
   
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Shareholder Matters
30
   
Item 13. Certain Relationships and Related Transactions
30
   
Item 14. Principal Accounting Fees and Services
30
   
Part IV
 
Item 15. Exhibits, Financial Statement Schedules
30





 
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 subsidiaries: FES; FSG; NGC and MYR. 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.

The Companies’ 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 11.2 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 7,500 square mile area of central and northeastern Ohio. The area it serves has a population of approximately 2.8 million.

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 a 1,500 square mile area of western Pennsylvania. The area served by Penn has a population of approximately 0.3 million.

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 1,700 square miles in northeastern Ohio. The area CEI serves has a population of approximately 1.9 million.

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 2,500 square miles in northwestern Ohio. The area TE serves has a population of approximately 0.8 million.

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 and operates major, high-voltage transmission facilities, which consist of approximately 7,100 circuit miles (5,814 pole miles) of transmission lines with nominal voltages of 345 kV, 138 kV and 69 kV. There are 37 interconnections with six neighboring control areas. ATSI’s transmission system offers gateways into the East through high capacity ties with PJM through Penelec, Duquesne Light Company and Allegheny Energy, Inc. into the North through multiple 345 kV high capacity ties with MEC, and into the South through ties with AEP and DPL. ATSI is the control area operator for the Ohio Companies and Penn service areas. ATSI plans, operates and maintains the transmission system in accordance with the requirements of the NERC and applicable regulatory agencies to ensure reliable service to FirstEnergy’s customers (see Transmission Rate Matters for a discussion of ATSI’s participation in the MISO).

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 northern, western and east central New Jersey. The area JCP&L serves has a population of approximately 2.5 million.

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 eastern and south central Pennsylvania. The area it serves has a population of approximately 1.2 million.

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 western, northern and south central Pennsylvania. The area it serves has a population of approximately 1.7 million. Penelec, as lessee of the property of its subsidiary, The Waverly Electric Light & Power Company, also serves a population of about 8,400 in Waverly, New York and its vicinity.

1


FES was organized under the laws of the State of Ohio in 1997 and provides energy-related products and services, and through its FGCO subsidiary, owns and operates FirstEnergy’s non-nuclear generation businesses (see Generation Asset Transfers below). FENOC was organized under the laws of the State of Ohio in 1998 and operates nuclear generating facilities. FSG is the parent company of several HVAC and energy management companies; MYR is a utility infrastructure construction service company. FESC provides legal, financial and other corporate support services to affiliated FirstEnergy companies.
 
           NGC was organized under the laws of the State of Ohio for the purpose of owning the nuclear generation assets transferred from the Ohio Companies and Penn in furtherance of those subsidiaries’ restructuring plans that were approved by the PUCO and, in the case of Penn, the PPUC. The intra-system transfer of nuclear generating assets was completed on December 16, 2005. The nuclear generating plant interests transferred do not include leasehold interests of OE and TE in certain of the nuclear plants that are subject to sale and leaseback arrangements with non-affiliates. NGC will sell all capacity, energy and ancillary services available from the transferred nuclear assets, as well as those related to the OE and TE leasehold interests and supplied to NGC pursuant to a power supply agreement with those companies, to FES pursuant to a power sale agreement for subsequent resale to wholesale and retail customers. FENOC operates and maintains the nuclear assets owned by NGC. NGC is a direct wholly owned subsidiary of FirstEnergy.

Reference is made to Note 16, Segment Information, of the Notes to Consolidated Financial Statements contained in Item 8 for information regarding FirstEnergy's reportable segments.

Generation Asset Transfers

On May 13, 2005, Penn, and on May 18, 2005, the Ohio Companies entered into certain agreements implementing a series of intra-system generation asset transfers that were completed in the fourth quarter 2005. The asset transfers resulted in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC, and FGCO, respectively. The generating plant interests transferred do not include leasehold interests of CEI, TE and OE in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.

On October 24, 2005, the Ohio Companies and Penn completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to FGCO’s purchase option under the Master Facility Lease.

On December 16, 2005, the Ohio Companies and Penn completed the intra-system transfer of their respective interests in the nuclear generation assets to NGC through, in the case of OE and Penn, a spin-off by way of dividend and, in the case of CEI and TE, a sale at net book value. FENOC continues to operate and maintain the nuclear generation assets.

These transactions were undertaken pursuant to the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. The transactions essentially completed the divestitures of owned assets contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants.

Divestitures

           In 2005, FirstEnergy sold three FSG subsidiaries - Pennsylvania-based Elliott-Lewis Corporation, Ohio-based Spectrum Control Systems, Inc. and Maryland-based L. H. Cranston and Sons, Inc. - and a MYR subsidiary - Power Piping Company, resulting in an aggregate after-tax gain of $13 million. All of these sales, with the exception of L. H. Cranston and Sons, Inc. met the discontinued operations criteria.

           In March 2005, FES completed the sale of its retail natural gas business for an after-tax gain of $5 million. Also in March 2005, FirstEnergy sold 51% of its interest in FirstCom, resulting in an after-tax gain of $4 million. FirstEnergy accounts for its remaining 31.85% interest in FirstCom on the equity basis.

 
2


Utility Regulation

           On August 8, 2005 President Bush signed into law the EPACT. This law has far reaching implications that will affect various aspects of electric generation, transmission and distribution. One of the most significant provisions of the new legislation gives the FERC authority to certify ERO that will establish and enforce mandatory bulk power liability standards, subject to FERC review and approval. The EPACT repealed PUHCA effective February 2006. PUHCA imposed financial and operational restrictions on many aspects of our business. Some of PUHCA’s consumer protection authority will be transferred to FERC and state utility commissions. FERC will now exercise authority over the issuance of certain securities and the assumption of certain liabilities. The EPACT also provides for tax credits for the development of certain clean coal and emissions technologies.

Each of the Companies’ retail rates, conditions of service, issuance of securities and other matters are also subject to regulation in the state in which each operates - Ohio by the PUCO, New Jersey by the NJBPU and in Pennsylvania by the PPUC. With respect to their wholesale and interstate electric operations and rates, the Companies are subject to regulation, including regulation of their accounting policies and practices, by the FERC. Under Ohio law, municipalities may regulate rates, subject to appeal to the PUCO if not acceptable to the utility.

Regulatory Accounting

The Companies and ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered from customers under the Companies' respective transition and regulatory plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies 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 regulatory assets are removed from the balance sheet in accordance with the guidance in SFAS 101.

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

·
restructuring the electric generation business and allowing the Companies’ customers to select a competitive electric generation supplier other than the Companies;
   
·
establishing or defining the PLR obligations to customers in the Companies’ service areas;
   
·
providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market;
   
·
itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges;
   
·
continuing regulation of the Companies’ transmission and distribution systems; and
   
·
requiring corporate separation of regulated and unregulated business activities.


 
3


Reliability Initiatives

   In late 2003 and early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task Force) regarding enhancements to regional reliability. In 2004, FirstEnergy completed implementation of all actions and initiatives related to enhancing area reliability, improving voltage and reactive management, operator readiness and training and emergency response preparedness recommended for completion in 2004. On July 14, 2004, NERC independently verified that FirstEnergy had implemented the various initiatives to be completed by June 30 or summer 2004, with minor exceptions noted by FirstEnergy, which exceptions are now essentially complete. FirstEnergy is proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, 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 as the result of adoption of mandatory reliability standards pursuant to the EPACT that could require additional, material expenditures. Finally, the PUCO is continuing to review the FirstEnergy filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

    As a result of outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L’s service reliability. In 2004, the NJBPU adopted an MOU that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L’s ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a Stipulation that incorporates the final report of a Special Reliability Master who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The Stipulation also incorporates the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L’s Planning and Operations and Maintenance programs and practices (Focused Audit). A final order in the Focused Audit docket was issued by the NJBPU on July 23, 2004. On February 11, 2005, JCP&L met with the Ratepayer Advocate to discuss reliability improvements. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.

In May 2004, the PPUC issued an order approving revised reliability benchmarks and standards, including revised benchmarks and standards for Met-Ed, Penelec and Penn. Met-Ed, Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004, due to their implementation of automated outage management systems following restructuring. On December 30, 2005 the ALJ recommended that the PPUC adopt the Joint Petition for Settlement among the parties involved in the three Companies’ request to amend the distribution reliability benchmarks, thereby eliminating the need for full litigation. The ALJ’s recommendation, adopting the revised benchmarks and standards was approved by the PPUC on February 9, 2006.

The EPACT provides for the creation of an ERO to establish and enforce reliability standards for the bulk power system, subject to FERC review. On February 3, 2006, the FERC adopted a rule establishing certification requirements for the ERO, as well as regional entities envisioned to assume monitoring responsibility for the new reliability standards.

The NERC has been preparing the implementation aspects of reorganizing its structure to meet the FERC’s certification requirements for the ERO. The NERC will make a filing with the FERC to obtain certification as the ERO and to obtain FERC approval of delegation agreements with regional entities. The new FERC rule referred to above, further provides for reorganizing regional reliability organizations (regional entities) that would replace the current regional councils and for rearranging the relationship with the ERO. The “regional entity” may be delegated authority by the ERO, subject to FERC approval, for enforcing reliability standards adopted by the ERO and approved by the FERC. NERC also intends to make a parallel filing with the FERC seeking approval of mandatory reliability standards. These reliability standards are expected to be based on the current NERC Version 0 reliability standards with some additional standards. The two filings are expected to be made in the second quarter of 2006.

The ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils have completed the consolidation of these regions into a single new regional reliability organization known as ReliabilityFirst Corporation. ReliabilityFirst began operations as a regional reliability council under NERC on January 1, 2006 and intends to file and obtain certification consistent with the final rule as a “regional entity” under the ERO during 2006. All of FirstEnergy’s facilities are located within the ReliabilityFirst region.

   On a parallel path, the NERC is establishing working groups to develop reliability standards to be filed for approval with the FERC following the NERC’s certification as an ERO. These reliability standards are expected to build on the current NERC Version 0 reliability standards. It is expected that the proposed reliability standards will be filed with the FERC in early 2006.

 
4


We believe that we are in compliance with all current NERC reliability standards. However, it is expected that the FERC will adopt stricter reliability standards than those contained in the current NERC Version 0 standards. The financial impact of complying with the new standards cannot be determined at this time. However, the EPACT required that all prudent costs incurred to comply with the new reliability standards be recovered in rates.

PUCO Rate Matters

On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a competitive bid process. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. In October 2004, the OCC and NOAC filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order in this proceeding as well as the associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral arguments on the appeals and it is expected that the Court will issue its opinion in 2006. On November 1, 2005, the Ohio Companies filed tariffs in compliance with the approved RSP, which were approved by the PUCO on December 7, 2005.

On May 27, 2005, the Ohio Companies filed an application with the PUCO to establish a GCAF rider under the RSP. The GCAF application sought recovery of increased fuel costs from 2006 through 2008 applicable to the Ohio Companies' retail customers through a tariff rider to be implemented January 1, 2006. The application reflected projected increases in fuel costs in 2006 compared to 2002 baseline costs. The new rider, after adjustments made in testimony, sought to recover all costs above the baseline (approximately $88 million in 2006). Various parties including the OCC intervened in this case and the case was consolidated with the RCP application discussed below.

On September 9, 2005, the Ohio Companies filed an application with the PUCO that supplemented their existing RSP with an RCP which was designed to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. Major provisions of the RCP include:

·  
Maintain the existing level of base distribution rates through December 31, 2008 for OE and TE, and April 30, 2009 for CEI;

 
·
Defer and capitalize for future recovery with carrying charges certain distribution costs to be incurred during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three years;

·  
Adjust the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized costs will occur as of December 31, 2008 for OE and TE as of December 31, 2010 for CEI;

·  
Reduce the deferred shopping incentive balances as of January 1, 2006 by up to $75 million for OE, $45 million for TE, and $85 million for CEI by accelerating the application of each respective company's accumulated cost of removal regulatory liability; and

·  
Recover increased fuel costs of up to $75 million, $77 million, and $79 million, in 2006, 2007, and 2008, respectively, from all OE and TE distribution and transmission customers through a fuel recovery mechanism. OE, TE, and CEI may defer and capitalize increased fuel costs above the amount collected through the fuel recovery mechanism (in lieu of implementation of the GCAF rider).

           On November 4, 2005, a supplemental stipulation was filed with the PUCO which was in addition to a stipulation filed with the September 9, 2005 application. On January 4, 2006, the PUCO approved the RCP filing with modifications. On January 10, 2006, the Ohio Companies filed a Motion for Clarification of the PUCO order approving the RCP. The Ohio Companies sought clarity on issues related to distribution deferrals, including requirements of the review process, timing for recognizing certain deferrals and definitions of the types of qualified expenditures. The Ohio Companies also sought confirmation that the list of deferrable distribution expenditures originally included in the revised stipulation fall within the PUCO order definition of qualified expenditures. On January 25, 2006, the PUCO issued an Entry on Rehearing granting in part, and denying in part, the Ohio Companies’ previous requests and clarifying issues referred to above. The Commission granted the Ohio Companies’ requests to: 1) recognize fuel and distribution deferrals commencing January 1, 2006; 2) recognize distribution deferrals on a monthly basis prior to review by the Commission Staff; 3) clarify that the types of distribution expenditures included in the Supplemental Stipulation may be deferred; and 4) clarify that distribution expenditures do not have to be “accelerated” in order to be deferred. The Commission granted the Ohio Companies’ methodology for determining distribution deferral amounts, but denied the Motion in that the Commission Staff must verify the level of distribution expenditures contained in current rates, as opposed to simply accepting the amounts contained in the Companies’ Motion. On February 3, 2006, several other parties filed applications for rehearing on the PUCO's January 4, 2006 Order. The Ohio Companies responded to the application for rehearing on February 13, 2006.

 
5


Under provisions of the RSP, the PUCO may require the Ohio Companies to undertake, no more often than annually, a competitive bid process to secure generation for the years 2007 and 2008. On July 22, 2005, FirstEnergy filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approved by the PUCO for the Ohio Companies in 2004, which resulted in the PUCO accepting no bids. Any acceptance of future competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and not until twelve months after the PUCO authorizes such termination. On September 28, 2005, the PUCO issued an Entry that essentially approved the Ohio Companies' filing but delayed the proposed timing of the competitive bid process by four months, calling for the auction to be held on March 21, 2006. OCC filed an application for rehearing of the September 28, 2005 Entry, which the PUCO denied on November 22, 2005. On February 23, 2006, the auction manager notified the PUCO that there was insufficient interest in the auction process to allow it to proceed in 2006.

On December 30, 2004, the Ohio Companies filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application sought recovery of these costs beginning January 1, 2006. The Ohio Companies requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. The PUCO approved the settlement stipulation on August 31, 2005. The incremental transmission and ancillary service revenues expected to be recovered from January through June 2006 are approximately $66 million. This amount includes the recovery of the 2005 deferred MISO expenses as described below. In May 2006, the Companies will file a modification to the rider to determine revenues from July 2006 through June 2007.

The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for the Ohio Companies to defer incremental transmission and ancillary service-related charges incurred as a participant in MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 30, 2004 was denied. The PUCO also authorized the Ohio Companies to accrue carrying charges on the deferred balances. On August 31, 2005, the OCC appealed the PUCO's decision. All briefs have been filed. A motion to dismiss filed on behalf of the PUCO is currently pending. Unless the court grants the motion, the appeal will be set for oral argument, which should be heard in the third or fourth quarter of 2006.

On January 20, 2006 the OCC sought rehearing of the PUCO approval of the rider recovery during the period January 1, 2006 through June 30, 2006, as that amount pertains to recovery of the deferred costs. The PUCO denied the OCC's application on February 6, 2006. The OCC has sixty days from that date to appeal the PUCO's approval of the rider.

PPUC Rate Matters

A February 2002 Commonwealth Court of Pennsylvania decision affirmed the June 2001 PPUC decision regarding approval of the FirstEnergy/GPU merger, remanded the issues of quantification and allocation of merger savings to the PPUC and denied Met-Ed and Penelec the rate relief initially approved in the PPUC decision. On October 2, 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC’s June 2001 order in its entirety. In accordance with the PPUC's direction, Met-Ed and Penelec filed supplements to their tariffs that became effective in October 2003 and that reflected the CTC rates and shopping credits in effect prior to the June 2001 order.

Met-Ed and Penelec had been negotiating with interested parties in an attempt to resolve the merger savings issues that are the subject of remand from the Commonwealth Court. Met-Ed’s and Penelec’s combined portion of total merger savings during 2001 - 2004 is estimated to be approximately $51 million. In late 2005, settlement discussions broke off as unsuccessful. A procedural schedule was established by the ALJ on January 17, 2006. The companies’ initial testimony is due on March 1, 2006 with testimony of the other parties and additional testimony by the companies to be filed through October, 2006. Hearings are scheduled for the end of October 2006 with the ALJ’s recommended decision to be issued in February 2007. The companies are unable to predict the outcome of this proceeding.

In an October 16, 2003 order, the PPUC approved September 30, 2004 as the date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC order also denied their accounting treatment request regarding the CTC rate/shopping credit swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. On October 22, 2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking that the Court reverse this PPUC finding; a Commonwealth Court judge subsequently denied their Objection on October 27, 2003 without explanation. On October 31, 2003, Met-Ed and Penelec filed an Application for Clarification of the Court order with the judge, a Petition for Review of the PPUC's October 2 and October 16, 2003 Orders, and an application for reargument, if the judge, in his clarification order, indicates that Met-Ed's and Penelec's Objection was intended to be denied on the merits. The Reargument Brief before the Commonwealth Court was filed on January 28, 2005.

 
6


As of December 31, 2005, Met-Ed's and Penelec's regulatory deferrals pursuant to the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation are $333 million and $48 million, respectively. Penelec's $48 million is subject to the pending resolution of taxable income issues associated with NUG Trust Fund proceeds.

Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sales agreement and a portion from contracts with unaffiliated third party suppliers, including NUGs. Assuming continuation of these existing contractual arrangements, the available supply represents approximately 100% of the combined retail sales obligations of Met-Ed and Penelec in 2006 and 2007; almost 100% for 2008; and approximately 85% for 2009 and 2010. Met-Ed and Penelec are authorized to defer any excess of NUG contract costs over current market prices. Under the terms of the wholesale agreement with FES, FES retains the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their contracts with NUGs and other unaffiliated suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR energy costs during the term of the agreement with FES. The wholesale agreement with FES is automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. On November 1, 2005, FES and the other parties thereto amended the agreement to provide FES the right over the next year to terminate the agreement at any time upon 60 days notice. If the wholesale power agreement were terminated or modified, Met-Ed and Penelec would need to satisfy the portion of their PLR obligations currently supplied by FES from unaffiliated suppliers at prevailing prices, which are likely to be higher than the current price charged by FES under the agreement and, as a result, Met-Ed’s and Penelec’s purchased power costs could materially increase. If Met-Ed and Penelec were to replace the 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 support an investment grade rating for its fixed income securities. Met-Ed and Penelec are in the process of preparing a comprehensive rate filing that will address a number of transmission, distribution and supply issues and is expected to be filed with the PPUC in the second quarter of 2006. That filing will include, among other things, a request for appropriate regulatory action to mitigate adverse consequences from any future reduction, in whole or in part, in the availability to Met-Ed and Penelec of supply under the existing FES agreement. There can be no assurance, however, that if FES ultimately determines to terminate, or significantly modify the agreement, timely regulatory relief will be granted by the PPUC or, to the extent granted, adequate to mitigate such adverse consequences.

On January 12, 2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005, estimated to be approximately $8 million per month. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association have all intervened in the case. To date, no hearing schedule has been established, and neither company has yet implemented deferral accounting for these costs.

On October 11, 2005, Penn filed a plan with the PPUC to secure electricity supply for its customers at set rates following the end of its transition period on December 31, 2006. Penn is recommending that the RFP process cover the period January 1, 2007 through May 31, 2008. Hearings were held on January 10, 2006 with Main Briefs filed on January 27, 2006 and Reply Briefs on February 3, 2006. On February 17, 2006, the ALJ issued a Recommended Decision to adopt Penn's RFP process with modifications. A PPUC vote is expected in April 2006. Under Pennsylvania's electric competition law, Penn is required to secure generation supply for customers who do not choose alternative suppliers for their electricity.

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 and costs incurred under NUG agreements exceed amounts collected through BGS and MTC rates and market sales of NUG energy and capacity. As of December 31, 2005, the accumulated deferred cost balance totaled approximately $541 million. New Jersey law allows for securitization of JCP&L's deferred balance upon application by JCP&L and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. On February 14, 2003, JCP&L filed for approval to securitize the July 31, 2003 deferred balance. JCP&L is in discussions with the NJBPU staff as a result of the stipulated settlement agreements (as further discussed below) which recommended that the NJBPU issue an order regarding JCP&L's application. On July 20, 2005, JCP&L requested the NJBPU to set a procedural schedule for this matter and is awaiting NJBPU action. On February 1, 2006, the NJBPU selected Bear Stearns as the financial advisor. On December 2, 2005, JCP&L filed a request for recovery of $165 million of actual above-market NUG costs incurred from August 1, 2005 through October 31, 2005 and forecasted above-market NUG costs for November and December 2005. The filing also includes a request for recovery of $49 million for above-market NUG costs incurred prior to August 1, 2003, to the extent those costs are not recoverable through securitization.

 
7


The 2003 NJBPU decision on JCP&L's base electric rate proceeding (the Phase I Order) disallowed certain regulatory assets and provided for an interim return on equity of 9.5% on JCP&L's rate base. The Phase I order also provided for a Phase II proceeding in which the NJBPU would review whether JCP&L is in compliance with current service reliability and quality standards and determine whether the expenditures and projects undertaken by JCP&L to increase its system's reliability are prudent and reasonable for rate recovery. Depending on its assessment of JCP&L's service reliability, the NJBPU could have increased JCP&L’s return on equity to 9.75% or decreased it to 9.25%.

On July 16, 2004, JCP&L filed the Phase II petition and testimony with the NJBPU, requesting an increase in base rates of $36 million for the recovery of system reliability costs and a 9.75% return on equity. The filing also requested an increase to the MTC deferred balance recovery of approximately $20 million annually.

On May 25, 2005, the NJBPU approved two stipulated settlement agreements. The first stipulation between JCP&L and the NJBPU staff resolves all of the issues associated with JCP&L's motion for reconsideration of the Phase I Order. The second stipulation between JCP&L, the NJBPU staff and the Ratepayer Advocate resolves all of the issues associated with JCP&L's Phase II proceeding. The stipulated settlements provide for, among other things, the following:

·  
An annual increase in distribution revenues of $23 million effective June 1, 2005, associated with the Phase I Order reconsideration;

·  
An annual increase in distribution revenues of $36 million effective June 1, 2005, related to JCP&L's Phase II Petition;

·  
An annual reduction in both rates and amortization expense of $8 million, effective June 1, 2005, in anticipation of an NJBPU order regarding JCP&L's request to securitize up to $277 million of its deferred cost balance;

·  
An increase in JCP&L's authorized return on common equity from 9.5% to 9.75%; and

·  
A commitment by JCP&L, through December 31, 2006 or until related legislation is adopted, whichever occurs first, to maintain a target level of customer service reliability with a reduction in JCP&L's authorized return on common equity from 9.75% to 9.5% if the target is not met for two consecutive quarters. The authorized return on common equity would then be restored to 9.75% if the target is met for two consecutive quarters.

The Phase II stipulation included an agreement that the distribution revenue increase also reflects a three-year amortization of JCP&L's one-time service reliability improvement costs incurred in 2003-2005. This resulted in the creation of a regulatory asset associated with accelerated tree trimming and other reliability costs which were expensed in 2003 and 2004. The establishment of the new regulatory asset of approximately $28 million resulted in an increase to net income of approximately $16 million ($0.05 per share of common stock) in the second quarter of 2005.

JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balance with the exception of 300 MW from JCP&L's NUG committed supply currently being used to serve BGS customers pursuant to NJBPU order for the period June 1, 2005 through May 31, 2006. New BGS tariffs reflecting the results of a February 2005 auction for the BGS supply became effective June 1, 2005.

The NJBPU decision approving the BGS procurement proposal for the period beginning June 1, 2006 was issued on October 12, 2005. JCP&L submitted a compliance filing on October 26, 2005, which was approved on November 10, 2005. The written Order was dated December 8, 2005. The auction took place in early February 2006 and the results have been approved by the NJBPU.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The Ratepayer Advocate filed comments on February 28, 2005. On March 18, 2005, JCP&L filed a response to those comments. A schedule for further 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 recent repeal of PUHCA under the EPACT. An NJBPU proposed rulemaking to address the issues was published in the NJ Register on December 19, 2005. The proposal would prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. A public hearing was held on February 7, 2006 and comments may be submitted to the NJBPU by February 17, 2006. JCP&L is not able to predict the outcome of this proceeding at this time.

 
8


FERC Rate Matters

   On November 1, 2004, ATSI requested authority from the FERC to defer approximately $54 million of vegetation management costs estimated to be incurred from 2004 through 2007. On March 4, 2005, the FERC approved ATSI's request to defer those costs ($26 million deferred as of December 31, 2005). ATSI expects to file an application with the FERC in 2006 that would include recovery of the deferred costs beginning June 1, 2006.
 
On January 24, 2006, ATSI and MISO filed an application with the FERC to modify the Attachment O formula rate mechanism to permit ATSI to accelerate recovery of revenues lost due to the FERC's elimination of through and out rates between MISO and PJM, and the elimination of other ATSI rates in the MISO tariff. Revenues formerly collected under these rates are currently used to reduce the ATSI zonal transmission rate in the Attachment O formula. The revenue shortfall created by elimination of these rates would not be fully reflected in ATSI's formula rate until June 1, 2006, unless the proposed Revenue Credit Collection is approved by the FERC. The Revenue Credit Collection mechanism is designed to collect approximately $40 million in revenues on an annualized basis beginning June 1, 2006. FERC is expected to act on this filing on or before April 1, 2006.

ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be involved in FERC hearings concerning the calculation and imposition of Seams Elimination Cost Adjustment (SECA) charges to various load serving entities. Pursuant to its January 30, 2006 Order, the FERC has compressed both phases of this proceeding into a single hearing scheduled to begin May 1, 2006, with an initial decision on or before August 11, 2006.

On January 31, 2005, certain PJM transmission owners made three filings pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On June 30, 2005, the PJM transmission owners filed a request for rehearing of the May 31, 2005 order. The rate design and formula rate proceedings are currently being litigated before the FERC. If FERC accepts AEP’s proposal to create a “postage stamp” rate for high voltage transmission facilities across PJM, significant additional transmission revenues would be imposed on JCP&L, Met-Ed, Penelec, and other transmission zones within PJM.

On November 1, 2005, FES filed two power sales agreements for approval with the FERC. One power sales agreement provided for FES to provide the PLR requirements of the Ohio Companies at a price equal to the retail generation rates approved by the PUCO for a period of three years beginning January 1, 2006. The Ohio Companies will be relieved of their obligation to obtain PLR power requirements from FES if the Ohio competitive bid process results in a lower price for retail customers. A similar power sales agreement between FES and Penn permits Penn to obtain its PLR power requirements from FES at a fixed price equal to the retail generation price during 2006. Penn has filed a plan with the PPUC to use an RFP process to obtain its power supply requirements after 2006.

On December 29, 2005, the FERC issued an order setting the two power sales agreements for hearing. The order criticizes the Ohio competitive bid process, and requires FES to submit additional evidence in support of the reasonableness of the prices charged in the Ohio and Pennsylvania Contracts. A pre-hearing conference was held on January 18, 2006 to determine the hearing schedule in this case. FES expects an initial decision to be issued in this case in the fall of 2006. The outcome of this proceeding cannot be predicted. FES has sought rehearing of the December 29, 2005 order.

Capital Requirements
 
              Capital expenditures for the Companies, FES and FirstEnergy’s other subsidiaries for the years 2006 through 2010 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.


 
9




   
2005
 
Capital Expenditures Forecast
 
   
Actual
 
2006
 
2007-2010
 
Total
 
   
(In millions)
 
OE
 
$
147
 
$
100
 
$
444
 
$
544
 
Penn
   
78
   
19
   
72
   
91
 
CEI
   
142
   
107
   
493
   
600
 
TE
   
62
   
54
   
174
   
228
 
JCP&L
   
205
   
174
   
750
   
924
 
Met-Ed
   
83
   
81
   
284
   
365
 
Penelec
   
111
   
83
   
386
   
469
 
ATSI
   
66
   
45
   
237
   
282
 
FES
   
182
   
215
   
2,042
   
2,257
 
NGC
   
20
   
208
   
591
   
799
 
Other subsidiaries
   
48
   
45
   
136
   
181
 
Total
 
$
1,144
 
$
1,131
 
$
5,609
 
$
6,740
 

During the 2006-2010 period, maturities of, and sinking fund requirements for, long-term debt of FirstEnergy and its subsidiaries are:

   
Long-Term Debt Redemption Schedule
 
   
2006
 
2007-2010
 
Total
 
   
(In millions)
 
                  
OE
 
$
3
 
$
185
 
$
188
 
Penn*
   
1
   
4
   
5
 
CEI**
   
-
   
395
   
395
 
TE
   
-
   
30
   
30
 
JCP&L
   
207
   
78
   
285
 
Met-Ed
   
100
   
150
   
250
 
Penelec
   
-
   
159
   
159
 
FirstEnergy
   
1,000
   
-
   
1,000
 
Other subsidiaries
   
13
   
26
   
39
 
Total
 
$
1,324
 
$
1,027
 
$
2,351
 
                     
* Penn has an additional $54 million of pollution control notes to be redeemed in January and February 2006 through the use of restricted cash and an additional $63 million due to associated companies in 2007-2010.
** CEI has an additional $54 million due to associated companies in 2007-2010.

FirstEnergy's investments for additional nuclear fuel during the 2006-2010 period are estimated to be approximately $711 million, of which about $169 million applies to 2006. During the same period, its nuclear fuel investments are expected to be reduced by approximately $560 million and $92 million, respectively, as the nuclear fuel is consumed. As a result of the intra-system generation assets transfers, NGC is now responsible for FirstEnergy's nuclear fuel investments. The following table displays the Companies' operating lease commitments, net of capital trust cash receipts for the 2006-2010 period.

 
 
Net
 
 
 
Operating Lease Commitments
 
 
 
2006
 
2007-2010
 
Total
 
 
 
(In millions)
 
OE
 
$
80
 
$
378
 
$
458
 
CEI
   
15
   
38
   
53
 
TE
   
82
   
291
   
373
 
JCP&L
   
2
   
7
   
9
 
Met-Ed
   
1
   
7
   
8
 
Total
 
$
180
 
$
721
 
$
901
 

FirstEnergy had approximately $731 million of short-term indebtedness as of December 31, 2005, comprised of $439 million in borrowings from a $2 billion revolving line of credit, $280 million in borrowings through $550 million of available accounts receivables financing and $12 million of other bank borrowings. Total short-term bank lines available to FirstEnergy and the Companies as of December 31, 2005 were approximately $2.6 billion.

On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered into a syndicated $2 billion five-year revolving credit facility that expires in June 2010. Borrowings under the facility are available to each Borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. As of December 31, 2005, FirstEnergy was the only borrower on this revolver with an outstanding balance of $439 million. The annual facility fees are 0.15% to 0.50%.

 
10


           FirstEnergy may borrow under these facilities and could transfer any of its borrowings to its subsidiaries. These revolving credit facilities, combined with an aggregate $550 million of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet our short-term working capital requirements and those of our subsidiaries. Total unused borrowing capability under existing facilities and accounts receivable financing facilities totaled $1.75 billion as of December 31, 2005. An additional source of ongoing cash for FirstEnergy, as a holding company, is cash dividends from its subsidiaries. In 2005, the holding company received $1.3 billion of cash dividends on common stock from its subsidiaries.

Based on their present plans, the Companies could provide for their cash requirements in 2006 from the following sources: funds to be received from operations; available cash and temporary cash investments as of December 31, 2005 (Company’s non-utility subsidiaries - $63 million, and OE - $1 million); the issuance of long-term debt (for refunding purposes); and funds available under revolving credit arrangements.

The extent and type of future financings will depend on the need for external funds as well as market conditions, the maintenance of an appropriate capital structure and the ability of the Companies to comply with coverage requirements in order to issue FMB and preferred stock. The Companies will continue to monitor financial market conditions and, where appropriate, may take advantage of economic opportunities to refund debt and preferred stock to the extent that their financial resources permit.

The coverage requirements contained in the first mortgage indentures under which the Companies issue FMB provide that, except for certain refunding purposes, the Companies may not issue FMB unless applicable net earnings (before income taxes), calculated as provided in the indentures, for any period of twelve consecutive months within the fifteen calendar months preceding the month in which such additional bonds are issued, are at least twice annual interest requirements on outstanding FMB, including those being issued. As of December 31, 2005, the Ohio Companies and Penn had the aggregate capability to issue approximately $1.2 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE and CEI are also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE and CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $651 million and $582 million, respectively, as of December 31, 2005. Under the provisions of its senior note indenture, JCP&L may issue additional FMB only as collateral for senior notes. As of December 31, 2005, JCP&L had the capability to issue $715 million of additional senior notes upon the basis of FMB collateral.

OE’s, Penn’s, TE’s and JCP&L’s respective articles of incorporation prohibit the sale of preferred stock unless applicable gross income, calculated as provided in the articles of incorporation, is equal to at least 1-1/2 times the aggregate of the annual interest requirements on indebtedness and annual dividend requirements on preferred stock outstanding immediately thereafter. Based upon applicable earnings coverage tests in their respective charters, OE, Penn, TE and JCP&L could issue a total of $5.5 billion of preferred stock (assuming no additional debt was issued) as of the end of 2005. CEI, Met-Ed and Penelec do not have similar restriction tests and could issue up to the number of preferred stock shares authorized under their respective charters (see Note 11(B) to FirstEnergy's Consolidated Financial Statements).

To the extent that coverage requirements or market conditions restrict the Companies’ abilities to issue desired amounts of FMB or preferred stock, the Companies 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.

As of December 31, 2005, approximately $1.0 billion was remaining under FirstEnergy’s shelf registration statement, filed with the SEC in 2003, to support future securities issues. The shelf registration provides the flexibility to issue and sell various types of securities, including common stock, debt securities, and share purchase contracts and related share purchase units.

Nuclear Regulation

           On January 20, 2006, FENOC announced that it has entered into a deferred prosecution agreement with the U.S. Attorney’s Office for the Northern District of Ohio and the Environmental Crimes Section of the Environment and Natural Resources Division of the DOJ related to FENOC’s communications with the NRC during the fall of 2001 in connection with NRC Bulletin 2001-01, “Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity” at the Davis-Besse Nuclear Power Station. Under the agreement, which expires on December 31, 2006, the United States also acknowledged FENOC's extensive corrective actions at Davis-Besse, FENOC's cooperation during the investigations by the DOJ and the NRC, FENOC's pledge of continued cooperation, FENOC's acknowledgement of responsibility for the behavior of its employees, and its agreement to pay a monetary penalty. The DOJ will refrain from seeking an indictment or otherwise initiating criminal prosecution of FENOC for all conduct related to the Statement of Facts attached to the deferred prosecution agreement, as long as FENOC remains in compliance with the agreement. As part of the agreement, FENOC paid a penalty of $28 million (which is not deductible for income tax purposes) which reduced FirstEnergy's earnings by $0.09 per common share in the fourth quarter of 2005. As part of the deferred prosecution agreement entered into with the DOJ, $4.35 million of that amount will be directed to community service projects.

 
11


On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head issue described above. FirstEnergy accrued $2 million for a potential fine prior to 2005 and accrued the remaining liability for the proposed fine during the first quarter of 2005. On September 14, 2005, FENOC filed its response to the NOV with the NRC. FENOC accepted full responsibility for the past failure to properly implement its boric acid corrosion control and corrective action programs. The NRC NOV indicated that the violations do not represent current licensee performance and that “the NRC does not anticipate taking further enforcement action in this matter, relative to FENOC, absent the DOJ developing new additional information.” FENOC paid the penalty in the third quarter of 2005. On January 23, 2006, FENOC supplemented its response to the NRC’s NOV on the Davis Besse head degradation to reflect the deferred prosecution agreement that FENOC had reached with the DOJ.

Effective July 1, 2005 the NRC oversight panel for Davis-Besse was terminated and Davis-Besse returned to the standard NRC reactor oversight process. At that time, NRC inspections were augmented to include inspections to support the NRC's Confirmatory Order dated March 8, 2004 that was issued at the time of startup and to address an NRC White Finding related to the performance of the emergency sirens. By letter dated December 8, 2005, the NRC advised FENOC that the White Finding had been closed.

On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee's failure to take prompt and corrective action. FENOC operates the Perry Nuclear Power Plant. In an April 4, 2005 public meeting discussing FENOC’s performance at Perry, the NRC stated that , overall the Perry Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. The NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. By an inspection report dated January 18, 2006, the NRC closed one of the white findings (related to emergency preparedness) which led to the multiple degraded cornerstones.

On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. The NRC reiterated this conclusion in its mid-year assessment letter dated August 30, 2005. On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance of Perry and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process, from increased oversight to possible impact to the plant’s operating authority. Although unable to predict a potential impact, its ultimate disposition could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

             As of December 16, 2005, NGC, a wholly owned subsidiary of FirstEnergy, acquired ownership of the nuclear generation assets transferred from OE, CEI, TE and Penn with the exception of leasehold interests of OE and TE in certain of the nuclear plants that are subject to sale and leaseback arrangements with non-affiliates.

Nuclear Insurance

             The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $10.8 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) $10.5 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 $100.6 million (but not more than $15 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 its present nuclear ownership and leasehold interests, FirstEnergy's maximum potential assessment under these provisions would be $402.4 million (OE - $34.4 million, NGC - $349.6 million, and TE - $18.4 million) per incident but not more than $60.0 million (OE - $5.1 million, NGC - $52.1 million, and TE - $2.8 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 has policies, renewable yearly, corresponding to its nuclear interests, which provide an aggregate indemnity of up to approximately $1.730 billion (OE - $150 million, NGC - $1.506 billion, TE - $74 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 $13.2 million (OE - $1.1 million, NGC - $11.6 million, and TE - $0.5 million).

 
12


            FirstEnergy is insured under property damage insurance provided by NEIL to the operating company for each plant. Under these arrangements, up to $2.75 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 $66.7 million (OE - $7.0 million, NGC - $55.3 million, TE - $3.6 million, Met Ed - $0.4 million, Penelec - $0.2 million and JCP&L - $0.2 million) during a policy year.

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 $1.06 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 the Companies with regard to air and water quality and other environmental matters. The effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on FirstEnergy’s earnings and competitive position. These environmental regulations affect FirstEnergy’s earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, FirstEnergy believes it is in compliance with existing regulations but is unable to predict future changes in regulatory policies and what, if any, the effects of such changes would be. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $1.8 billion for 2006 through 2010.

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

On December 1, 2005, FirstEnergy issued a comprehensive report to shareholders regarding air emissions regulations and an assessment of its future risks and mitigation efforts. The report is available on FirstEnergy’s web site at www.firstenergycorp.com/environmental.

Clean Air Act Compliance

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

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

 
13


           FirstEnergy, GPU and Met-Ed, along with the current owner of the Portland Generation Station, Reliant, and the purchaser of Portland Station in 1999, Sithe Energy, all received a notification letter from New Jersey's Attorney General (NJAG) dated November 16, 2005 alleging Clean Air Act violations at the Portland Station. Specifically, the NJAG alleges that "modifications" at Portland Units 1 and 2 occurred between 1979 and 1995 without preconstruction new source review or permitting required by the CAA's prevention of significant deterioration (PSD) program and states that unless the Companies abate the alleged violations, New Jersey may commence an action seeking injunctive relief, penalties and mitigation of the harm caused by excess emissions. Although it remains liable to Sithe Energy under a 1998 purchase agreement for civil penalties and fines, Met-Ed did not indemnify or remain responsible for any permitting or other environmental representations or warranties which the 1998 agreement specifically provides did not survive closing. No liability has been accrued as of December 31, 2005.

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the “Clean Air Interstate Rule” (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 provides each affected state until 2006 to develop implementing regulations to achieve additional reductions of NOx and SO2 emissions in two phases (Phase I in 2009 for NOx, 2010 for SO2 and Phase II in 2015 for both NOx and SO2). FirstEnergy’s Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to the caps on SO2 and NOx emissions, whereas their New Jersey fossil-fired generation facilities will be subject to a cap on NOx emissions only. According to the EPA, SO2 emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions in affected states to just 2.5 million tons annually. NOx emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NOx cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FirstEnergy operates affected facilities.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, mercury emissions will be capped nationally at 38 tons by 2010 (as a “co-benefit” from implementation of SO2 and NOx emission caps under the EPA’s CAIR program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the CAMR have been challenged in the United States Court of Appeals for the District of Columbia. FirstEnergy’s future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which we operate affected facilities.

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

W. H. Sammis Plant

           In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement was approved by the Court on July 11, 2005, and requires reductions of NOx and SO2 emissions at the W. H. Sammis Plant and other coal fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergy could be exposed to penalties under the settlement agreement. Capital expenditures necessary to meet those requirements are currently estimated to be $1.5 billion (the primary portion of which is expected to be spent in the 2008 to 2011 time period). On August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of sulfur dioxide emissions. The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy purchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million. Results in 2005 included the penalties payable by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized liabilities of $9.2 million and $0.8 million, respectively, for probable future cash contributions toward environmentally beneficial projects.

 
14


Climate Change

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

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

Clean Water Act

Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to the Companies' plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to the Companies' 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 species are drawn into a facility’s cooling water system. The Companies are conducting comprehensive demonstration studies, due in 2008, to determine the operational measures, equipment or restoration activities, if any, necessary for compliance by its facilities with the performance standards. The Companies are unable to predict the outcome of such studies. Depending on the outcome of such studies, the future cost of compliance with these standards may require material capital expenditures.

Regulation of Hazardous Waste

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

The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of December 31, 2005, based on estimates of the total costs of cleanup, the Companies’ proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Total liabilities of approximately $64 million have been accrued through December 31, 2005.

Fuel Supply

FirstEnergy currently has long-term coal contracts to provide approximately 20.5 million tons for the year 2006. The contracts are shared among the Companies based on various economic considerations. This contract coal is produced primarily from mines located in Pennsylvania, Kentucky, Wyoming, West Virginia and Ohio. The contracts expire at various times through December 31, 2021.

FirstEnergy estimates its 2006 coal requirements to be approximately 23.1 million tons to be met from the long-term contracts as well as from spot market purchases. See “Environmental Matters” for factors pertaining to meeting environmental regulations affecting coal-fired generating units.

 
15


FirstEnergy has contracts for uranium material and conversion services through 2008. The enrichment services are contracted for all of the enrichment requirements for nuclear fuel through 2006. A portion of enrichment requirements is also contracted through 2011. Fabrication services for fuel assemblies are contracted for the next two reloads for Beaver Valley Unit 1, the next two reloads for Beaver Valley Unit 2 (through approximately 2007 and 2006, respectively), the next reload for Davis-Besse (through approximately 2006) and through the operating license period for Perry (through approximately 2026). The Davis-Besse fabrication contract also has an extension provision for services 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 2008, respectively. With the plant modifications completed in 2002, Davis-Besse has adequate storage through the remainder of its current operating license period. After current on-site storage capacity is exhausted, additional storage capacity will have to be obtained either through plant modifications, interim off-site disposal, or permanent waste disposal facilities. 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. CEI, TE, OE and Penn have contracts with the U.S. Department of Energy (DOE) for the disposal of spent fuel for Beaver Valley, Davis-Besse and Perry. On February 15, 2002, President Bush approved the DOE’s recommendation of Yucca Mountain for underground disposal of spent nuclear fuel from nuclear power plants and high level waste from U.S. defense programs. The approval by President Bush enables the process to proceed to the licensing phase. Based on the DOE schedule published in the July 1999 Draft Environmental Impact Statement, the Yucca Mountain Repository is currently projected to start receiving spent fuel in 2010. The Repository is expected to be delayed further as the result of an announced delay in submission of the license application. The Companies intend to make additional arrangements for storage capacity as a contingency for further delays with the DOE acceptance of spent fuel for disposal past 2010.

System Capacity and Reserves

The 2005 net maximum hourly demand for each of the Companies was: OE-6,303 MW (including an additional 387 MW of firm power sales under a contract which ended December 31, 2005) on July 25, 2005; Penn-1,106 MW (including an additional 47 MW of firm power sales under a contract which ended December 31, 2005) on July 26, 2005; CEI-4,522 MW on July 25, 2005; TE-2,138 MW on July 25, 2005; JCP&L-6,279 MW on July 27, 2005; Met-Ed-2,850 MW on August 4, 2005; and Penelec-2,875 MW on August 4, 2005. JCP&L’s load is supplied through the New Jersey BGS Auction process, transferring the full 6,135 MW load obligation to other parties. FES participated in the auction and is currently responsible for a 300 MW segment of that load through May 2006.

Based on existing capacity plans, ongoing arrangements for firm purchase contracts, and anticipated term power sales and purchases, FirstEnergy has sufficient supply resources to meet load obligations. The current FirstEnergy capacity portfolio contains 13,427 MW of owned generation, 480 MW of generation from our 20.5% ownership of OVEC, and approximately 1,600 MW of long-term purchases from NUGs. FirstEnergy has also entered into approximately 275 MW of long-term purchase contracts for renewable energy from wind resources. Any remaining load obligations will be met through a mix of multi-year forward purchases, short-term forward purchases (less than one year) and spot market purchases. FirstEnergy's sources of generation during 2005 were 64% and 36% from coal and nuclear, respectively.

Regional Reliability

The Ohio Companies and Penn participate with 24 other electric companies operating in nine states in ECAR, which was organized for the purpose of furthering the reliability of bulk power supply in the area through coordination of the planning and operation by the ECAR members of their bulk power supply facilities. The ECAR members have established principles and procedures regarding matters affecting the reliability of the bulk power supply within the ECAR region. Procedures have been adopted regarding: i) the evaluation and simulated testing of systems’ performance; ii) the establishment of minimum levels of daily operating reserves; iii) the development of a program regarding emergency procedures during conditions of declining system frequency; and iv) the basis for uniform rating of generating equipment.

           The ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils have completed the consolidation of these regions into a single new regional reliability organization known as ReliabilityFirst Corporation. ReliabilityFirst began operations as a regional reliability council under NERC on January 1, 2006 and intends to file and obtain certification consistent with the final rule as a “regional entity” under the ERO during 2006. All of FirstEnergy’s facilities are located within the ReliabilityFirst region.

The transmission facilities of JCP&L, Met-Ed and Penelec are operated by PJM. PJM is the organization responsible for the operation and control of the bulk electric power system throughout major portions of five Mid-Atlantic states and the District of Columbia. PJM is dedicated to meeting the reliability criteria and standards of NERC and the Mid-Atlantic Area Council.

 
16


Competition

The Companies compete with other utilities for intersystem bulk power sales and for sales to municipalities and cooperatives. The Companies also compete with suppliers of natural gas and other forms of energy in connection with their industrial and commercial sales and in the home climate control market, both with respect to new customers and conversions, and with all other suppliers of electricity. To date, there has been no substantial cogeneration by the Companies’ customers.

As a result of actions taken by state legislative bodies over the last few years, major changes in the electric utility business are occurring in parts of the United States, including Ohio, New Jersey and Pennsylvania where FirstEnergy’s utility subsidiaries operate. These changes have resulted in fundamental alterations in the way traditional integrated utilities and holding company systems, like FirstEnergy, conduct their business. In accordance with the Ohio electric utility restructuring law under which Ohio electric customers could begin choosing their electric generation suppliers starting in January 2001, FirstEnergy has further aligned its business units to accommodate its retail strategy and participate in the competitive electricity marketplace in Ohio. The organizational changes deal with the unbundling of electric utility services and new ways of conducting business. FirstEnergy’s Power Supply Management Services segment participates in deregulated energy markets in Ohio, Pennsylvania, New Jersey and Michigan.

Competition in Ohio’s electric generation began on January 1, 2001. Pursuant to the generation asset transfers on October 24, 2005 and December 16, 2005, FGCO and NGC now own nearly all of the fossil and nuclear generation assets, respectively, previously owned by the Companies. The Companies continue to provide generation services to regulated franchise customers who have not chosen an alternative, competitive generation supplier, except in New Jersey where JCP&L’s obligation to provide BGS has been removed through a transitional mechanism of auctioning the obligation (see “NJBPU Rate Matters”). In September 2002, Met-Ed and Penelec assigned their PLR responsibility to FES through a wholesale power sale agreement. Under the terms of the wholesale agreement, FES assumed the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec (see “PPUC Rate Matters” for further discussion). The Ohio Companies and Penn obtain their generation through power supply agreements with FES.

Research and Development

The Companies participate in funding the Electric Power Research Institute (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 major portion of EPRI research and development projects is directed toward practical solutions and their applications to problems currently facing the electric utility industry.

Executive Officers

 
   
 
Position Held During Past Five Years
 
Name
Age
Dates
       
A. J. Alexander (A) (B)
54
President and Chief Executive Officer
2004-present
   
President and Chief Operating Officer
2001-2004
   
President
*-2001
       
L. M. Cavalier
54
Senior Vice President
2005-present
   
Vice President - Human Resources
2001-2005
   
President - Eastern Region
*-2001
       
M. T. Clark
55
Senior Vice President
2004-present
   
Vice President - Business Development
* -2004
       
K. W. Dindo
56
Vice President and Chief Risk Officer
2001-present
   
Vice President
*-2001
       
D. S. Elliott (B)
51
President - Pennsylvania Operations
2005-present
   
Senior Vice President
2001-2005
   
Vice President
*-2001
       
R. R. Grigg (A) (B)
57
Executive Vice President and Chief Operating Officer
2004-present
   
President and Chief Executive Officer - WE Generation
*-2004
 


 
17




       
C. E. Jones (A) (B)
50
Senior Vice President
2003-present
   
Vice President - Regional Operations
2001-2003
   
President - Northern Region
*-2001
       
C. D. Lasky
43
Vice President - Fossil Operations
2004-present
   
Plant Director
2003-2004
   
Assistant Plant Director
*-2003
       
G. R. Leidich
55
President and Chief Nuclear Officer - FENOC
2003-present
   
Executive Vice President - FENOC
2002-2003
   
Executive Vice President - Institute of Nuclear Power Operations
*-2002
       
D. C. Luff
58
Senior Vice President
2005-present
   
Vice President
2001-2005
   
Manager of State Governmental Affairs
*-2001
       
R. H. Marsh (A) (B) (C)
55
Senior Vice President and Chief Financial Officer
2001-present
   
Vice President and Chief Financial Officer
*-2001
       
S. E. Morgan (C)
55
President - JCP&L
2003-present
   
Vice President - Energy Delivery
2002-2003
   
President - Central Region
*-2002
       
J. M. Murray (A)
59
President - Ohio Operations
2005-present
   
President - Western Region
*-2005
       
T. C. Navin
47
Vice President
2005-present
   
Treasurer
*-2005
       
J. F. Pearson (A) (B) (C)
51
Treasurer
2005-present
   
Group Controller - Strategic Planning and Operations
2004-2005
   
Controller - FES
2003-2004
   
Director - FES
2001-2003
   
Manager - Budget and Business Planning
*-2001
       
G. L. Pipitone
55
President - FES
2004-present
   
Senior Vice President
2001-2004
   
Vice President
*-2001
       
D. R. Schneider
44
Vice President - Commodity Operations
2004-present
   
Vice President - Fossil Operations
2001-2004
   
Plant Manager
*-2001
       
C. B. Snyder
60
Senior Vice President
2001-present
   
Executive Vice President - Corporate Affairs - GPU
*-2001
       
B. F. Tobin
45
Vice President and Chief Procurement Officer
2005-present
   
Vice President
2005
   
Vice President and Chief Information Officer
2004-2005
   
Vice President and Chief Procurement Officer
2001-2004
   
Senior Manager - Accenture
*-2001
       
L. L. Vespoli (A) (B) (C)
46
Senior Vice President and General Counsel
2001-present
   
Vice President and General Counsel
*-2001
       
H. L. Wagner (A) (B) (C)
53
Vice President, Controller and Chief Accounting Officer
2001-present
   
Controller and Chief Accounting Officer
*-2001
       
T. M. Welsh
56
Senior Vice President
2004-present
   
Vice President - Communications
2001-2004
   
Manager - Communications Services
*-2001

(A) Denotes executive officers of OE, CEI and TE.
(B) Denotes executive officers of Met-Ed, Penelec and Penn.
(C) Denotes executive officers of JCP&L.
* Indicates position held at least since January 1, 2001.

 
18


Employees

As of January 1, 2006, FirstEnergy’s nonutility subsidiaries and the Companies had a total of 14,586 employees (excluding MYR) located in the United States as follows:

FESC
2,918
OE
1,221
CEI
949
TE
431
Penn
201
JCP&L
1,416
Met-Ed
678
Penelec
867
ATSI
36
FES
1,957
FENOC
2,735
FSG
1,177
Total
14,586

Of the above employees, 7,027 (including 229 for FESC, 740 for OE, 667 for CEI, 328 for TE, 148 for Penn, 1,120 for JCP&L, 508 for Met-Ed, 612 for Penelec, 1,161 for FES, 934 for FENOC and 580 for FSG) are covered by collective bargaining agreements.

           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 Arbitrator decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the Arbitrator issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, the federal court granted a union motion to dismiss JCP&L's appeal as premature. JCP&L will file its appeal again in federal district court once the damages associated with this case are identified at an individual employee level. JCP&L recognized a liability for the potential $16 million award in 2005.

FirstEnergy Website

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 website at www.firstenergycorp.com. These reports are posted on the website as soon as reasonably practicable after they are electronically filed with the SEC.

ITEM 1A. RISK FACTORS

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

Operation of generation, transmission and distribution facilities involves risk, including potential breakdown or failure of equipment or processes, accidents, labor disputes, stray voltage 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 those 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 or increased expenses, including higher maintenance costs. Unplanned outages may require us to incur significant replacement power costs. Moreover, if we were unable to perform under contractual obligations, penalties or liability for damages could result. OE, CEI, and TE are exposed to losses under their applicable sale-leaseback agreements for certain generating facilities upon the occurrence of certain contingent events that could render these facilities worthless. Although we believe these types of events are unlikely to occur, OE, CEI and TE each have a maximum exposure to loss under these provisions of approximately $1 billion.

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 and other resources. Failure to provide safe and reliable service and failure to meet regulatory reliability standards due to a number of factors, including equipment failure and weather, could adversely affect our operating results through reduced revenues and increased capital and maintenance costs and the imposition of penalties/fines or other adverse regulatory outcomes.

 
19


Changes in Commodity Prices Could Adversely Affect Our Profit Margins
 
While much of our generation currently serves customers under retail rates set by regulatory bodies, we also purchase and sell electricity in the competitive wholesale and retail markets. Increases in the costs of fuel for our generation facilities (particularly coal and natural gas) can affect our profit margins in both competitive and non-competitive markets. Changes in the market prices 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 obligations in Ohio and Pennsylvania.

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.

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

            FirstEnergy is 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 the operation of 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.

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.

FirstEnergy’s nuclear facilities are insured under NEIL policies issued for each plant. Under these policies, up to $2.75 billion of insurance coverage is provided for property damage and decontamination and decommissioning costs. We have also obtained approximately $1.7 billion of insurance coverage for replacement power costs. Under these policies, we can be assessed a maximum of approximately $80 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.

 
20


Regulatory Changes in the Electric Industry Could Affect Our Competitive Position and Result in Unrecoverable Costs Adversely Affecting Our Business and Results of Operations

As a result of the actions taken by state legislative bodies over the last few years, changes in the electric utility business have occurred and are continuing to take place in states 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 integrated utilities conduct their business.

Increased competition resulting from restructuring efforts, including but not limited to, the implementation by regulators of periodic competitive bid processes for generation supply, could have an adverse financial impact on us and consequently on our results of operations. Increased competition could result in additional pressure to lower prices, including the price of electricity, potentially resulting in impairment of assets, loss of retail customers, lower profit margins and increased costs of capital. We cannot predict the extent or timing of entry by additional competitors into the electric markets.

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 and deregulation efforts result in increased competition or unrecoverable costs, our business and results of operations may be adversely affected. We cannot predict the extent or timing of further efforts to restructure, deregulate or re-regulate our business or the industry.

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 would 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.

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.

On August 8, 2005 President Bush signed into law the EPACT. This federal legislation will affect various aspects of electric generation, transmission and distribution. One of the provisions of the new legislation gives the FERC the authority to certify an ERO that will establish and enforce mandatory bulk power reliability standards, subject to FERC review and approval. The EPACT repealed PUHCA effective February 8, 2006. Some of PUHCA’s consumer protection authority have been transferred to the FERC and state utility commissions. The repeal of PUHCA and the impact of this legislation and its implementation on both a federal and state level could have a significant impact on our operations.

Costs of Compliance with Environmental Laws are Significant, and the Cost of Compliance with Future Environmental Laws Could Adversely Affect Cash Flow and Profitability

Certain of our subsidiaries’ operations are subject to extensive federal, state and local environmental statutes, rules and regulations. Compliance with these legal requirements requires us to incur costs toward environmental monitoring, installation of pollution control equipment, emission fees, maintenance, upgrading, remediation and permitting at all of 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 FirstEnergy or its subsidiaries 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.

 
21


There have been recent changes in the EPA’s final CAIR, CAMR and CAVR. As a result of those changes the states have been given substantial discretion in developing their own rules to implement these programs. In addition, both the CAIR and the CAMR have been challenged in the United States Court of Appeals for the District of Columbia. As a result, the ultimate requirements of these rules may not be known for several years and may depart significantly from the current rules. If the final rules are remanded by the Court, if states elect not to participate in the various federal programs under the rules, or if the states elect to impose additional requirements on individual units that are already subject to the CAIR, the CAMR and/or the CAVR, our costs of compliance could increase significantly and could have an adverse effect on future results of operations, cash flows and financial condition.

Alternatively, if the final rules are remanded by the Court and their implementation is postponed, we could be competitively disadvantaged because we are currently obligated to comply with essentially this same level of emission controls as a result of our settlement of the New Source Review Litigation related to our W. H. Sammis Plant.

There Are Uncertainties Relating to Our Participation in the PJM and MISO Regional Transmission Organizations

Market rules that govern the operation of RTOs 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 RTO 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. We are incurring significant additional fees and increased costs to participate in an RTO, and may be limited by state retail rate caps with respect to the price at which power can be sold to retail customers. 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 due to state retail rate caps. In addition, we may be required to expand our transmission system according to decisions made by an RTO rather than our internal planning process. 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, and whether state regulatory commissions will permit full and timely recovery of RTO or market-imposed costs, we cannot fully assess the impact that these power markets or other ongoing RTO developments may have on us.

Weather Conditions such as Tornadoes, Hurricanes, Ice Storms and Droughts, as Well as Seasonal Temperature Variations Could Have a Negative Impact on Our Results of Operations

Weather conditions directly influence the demand for electric power. In our service areas, demand for power peaks during the summer months, with market prices also typically peaking at that time. As a result, overall operating results may fluctuate on a seasonal and quarterly basis. In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder. Severe weather, such as tornadoes, hurricanes, storms, ice, 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.

We Are Subject to Financial Performance Risks Related to the Economic Cycles of the Electric Utility Industry

Our business follows the economic cycles of our customers. Sustained downturns or sluggishness in the economy generally affects the markets in which we operate and negatively influences our energy operations. Declines in demand for electricity as a result of economic downturns will reduce overall electricity sales and lessen our cash flows, especially as industrial customers reduce production, resulting in less consumption of electricity. Economic conditions also impact the rate of delinquent customer accounts receivable.

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 operating results from future regulatory activities of any of these agencies.

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

Workforce demographic issues challenge employers nationwide and are of particular concern to the electric utility industry. The median age of utility workers is significantly higher than the national average. Today, nearly one-half of the industry’s workforce is age 45 or higher. Consequently, we face the difficult challenge of finding 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.

 
22


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 manage the market risk inherent in our energy and fuel and debt positions. We have implemented procedures 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 against all of our exposures in these areas and our risk management program may not operate as planned. For instance, 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.

We also face credit risks that parties with whom we contract 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 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 would likely be adversely affected.

Interest Rates and/or a Credit Ratings Downgrade Could Negatively Affect Our Financing Costs and Our Ability to Access Capital

We have near-term exposure to interest rates from outstanding indebtedness indexed to variable interest rates, and we have exposure to future interest rates as we plan to raise debt in the capital markets to meet maturing debt obligations and fund construction or other investment opportunities. Interest rates could change in significant ways 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.

We rely on access to bank and capital markets as sources of liquidity for cash requirements not satisfied by cash flows 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 in place of letters of credit and other guarantees. A ratings downgrade would also increase the fees we pay on our various credit facilities, thus increasing the cost of our working capital. A ratings 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, Moody’s, and Fitch are investment grade. The current ratings outlook from S&P is stable and the ratings outlook from Moody’s and Fitch is positive.

We Must Rely on Cash From Our Subsidiaries

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 needs are 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.

We May Ultimately Incur Liability in Connection with Federal Proceedings

On December 10, 2004, FirstEnergy received a letter from the United States Attorney’s Office stating that FENOC is a target of the federal grand jury investigation into alleged false statements made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. On January 20, 2006, FENOC announced that it had entered into a deferred prosecution agreement with the U.S. Attorney’s Office for the Northern District of Ohio and the Environmental Crimes Section of the Environment and Natural Resources Division of the Department of Justice (collectively, the “Department”) related to certain statements made by FENOC employees to the NRC during the period September 3, 2001 through November 28, 2001 with respect to the Davis-Besse Nuclear Power Station. Under the Agreement, FENOC paid a penalty of $28 million and agreed to cooperate with the United States and NRC during the term of the Agreement (which runs through December 31, 2006) in all criminal and administrative investigations and proceedings related to the conduct described in the Statement of Facts attached to the Agreement.

 
23


In consideration for FENOC’s (i) $28 million payment, (ii) cooperation as described above, (iii) acceptance and acknowledgement of responsibility for its conduct as described in the Statement of Facts attached to the Agreement, (iv) compliance with federal criminal laws, and (v) continued compliance with the terms of the Agreement, the Department has agreed to refrain from seeking an indictment or otherwise initiating criminal prosecution of FENOC for the conduct described in the Statement of Facts attached to the Agreement. If the Department determined that FENOC failed to comply with the terms of the Agreement, it could seek an indictment or begin criminal proceedings against FENOC, which could have an adverse impact on our results of operations and financial condition.

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC’s Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC’s formal order of investigation also encompasses issues raised during the SEC’s examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a subpoena asking for documents relating to issues raised during the SEC’s PUHCA examination. On August 24, 2005, additional information was requested regarding Davis-Besse. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.

Acts of War or Terrorism Could Negatively Impact Our Business

The possibility that our infrastructure, or that of an interconnected company, such as electric generation, transmission and distribution facilities could be direct targets of, or indirect casualties of, an act of war could affect our operations. Our generation plants, transmission and distribution facilities, or those of interconnected companies, may be targets of terrorist activities that 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES
 
The Companies’ respective first mortgage indentures constitute, in the opinion of the Companies’ counsel, direct first liens on substantially all of the respective Companies’ physical property, subject only to excepted encumbrances, as defined in the indentures. See the “Leases” and “Capitalization” notes to the respective financial statements for information concerning leases and financing encumbrances affecting certain of the Companies’ properties.

FirstEnergy owns, and/or leases, the following generating units in service as of March 1, 2006, shown in the table below. Except for the leasehold interests 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.

 
24



       
Net
 
       
Demonstrated
 
       
Capacity
 
       
(MW)
 
       
Owned
 
   
Unit
 
Total
 
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
   
780
(b)
     
3
   
800
(c)
               
W. H. Sammis-
   
1-6
   
1,620
 
Stratton, OH
   
7
   
600
 
Total
         
7,389
 
               
Nuclear Units
             
Beaver Valley-
   
1
   
821
 
Shippingport, PA
   
2
   
821
(d)
Davis-Besse-
   
 
       
Oak Harbor, OH
   
1
   
883
 
Perry-
             
N. Perry Village, OH
   
1
   
1,260
(e)
Total
         
3,785
 
               
Oil/Gas-Fired/
             
Pumped Storage Units
             
Richland-Defiance, OH
   
1-3
   
42
 
     
4-6
   
390
 
Seneca-Warren, PA
   
1-3
   
435
 
Sumpter-Sumpter Twp, MI
   
1-4
   
340
 
West Lorain
   
1-1
   
120
 
Lorain, OH
   
2-6
   
425
 
Yard’s Creek-Blairstown
             
Twp., NJ
   
1-3
   
200
 
Other
         
301
 
Total
         
2,253
 
Total
         
13,427
 


Notes:
(a)
Includes CEI’s leasehold interest in Bruce Mansfield Unit 1 of 6.50% (54 MW).
 
 
(b)
Includes CEI’s and TE’s leasehold interests in Bruce Mansfield Unit 2 of 28.6% (223 MW) and
17.30% (135 MW), respectively.
 
 
(c)
Includes CEI’s and TE’s leasehold interests in Bruce Mansfield Unit 3 of 24.47% (196 MW) and
19.91% (159 MW), respectively.
 
 
(d)
Includes OE’s and TE’s leasehold interests in Beaver Valley Unit 2 of 21.66% (178 MW) and
18.26% (150 MW), respectively.
 
 
(e)
Includes OE’s leasehold interest in Perry of 12.58% (159 MW).
 
 
Prolonged outages of existing generating units might make it necessary for FirstEnergy, depending upon the demand for electric service upon their system, to use to a greater extent than otherwise, less efficient and less economic generating units, or purchased power, and in some cases may require the reduction of load during peak periods under FirstEnergy interruptible programs, all to an extent not presently determinable.

FirstEnergy's 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 Companies’ overhead and underground transmission lines aggregate 14,980 pole miles.

 
25


The Companies’ electric distribution systems include 115,641 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 91,323,000 kilovolt-amperes.

The transmission facilities that are owned and operated by ATSI also interconnect with those of AEP, DPL, Duquesne, Allegheny, Met-Ed and Penelec. The transmission facilities of JCP&L, Met-Ed and Penelec are physically interconnected and are operated on an integrated basis as part of the PJM RTO.

FirstEnergy’s distribution and transmission systems as of December 31, 2005, consist of the following:

           
Substation
 
   
Distribution
 
Transmission
 
Transformer
 
   
Lines
 
Lines
 
Capacity
 
   
(Miles)
 
(kV-amperes)
 
               
OE
   
29,839
   
550
   
8,298,000
 
Penn
   
5,717
   
44
   
1,739,000
 
CEI
   
24,973
   
2,144
   
9,301,000
 
TE
   
1,748
   
223
   
3,677,000
 
JCP&L
   
18,812
   
2,106
   
21,154,000
 
Met-Ed
   
14,666
   
1,407
   
9,985,000
 
Penelec
   
19,886
   
2,690
   
14,238,000
 
ATSI*
   
-
   
5,816
   
22,931,000
 
Total
   
115,641
   
14,980
   
91,323,000
 

 
*
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 the Notes to Consolidated Financial Statements contained in Item 8 for a description of certain legal proceedings involving FirstEnergy, OE, CEI, TE, Penn, 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 pages 3-5 of FirstEnergy’s 2005 Annual Report to Stockholders (Exhibit 13). Information for OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec is not required to be disclosed because they are wholly owned subsidiaries.

The table below includes information on a monthly basis for the fourth quarter, regarding purchases made by FirstEnergy of its common stock during the fourth quarter of 2005.

   
Period
 
   
October 1-31,
2005
 
November 1-30,
2005
 
December 1-31,
2005
 
Fourth
Quarter
 
Total Number Of Shares Purchased (a)
   
283,046
   
63,013
   
268,707
   
614,766
 
Average Price Paid per Share
 
$
52.14
 
$
46.75
 
$
47.27
 
$
49.46
 
Total Number of Shares Purchased As Part of Publicly 
   
 
             
 Announced Plans Or Programs (b)    
-
   
-
   
-
   
-
 
Maximum Number (or Approximate Dollar Value) of Shares that
  May Yet Be Purchased Under the Plans Or Programs
   
-
   
-
   
-
   
-
 

(a)
Share amounts reflect purchases on the open market to satisfy FirstEnergy’s obligations to deliver common stock under its Executive and Director Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the Executive and Director Incentive Compensation Plan.
(b)
FirstEnergy does not currently have any publicly announced plan or program for share purchases.
 

 
 
26


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 Results of Operations and Financial Condition, and Financial Statements included on the pages shown in the following table in the respective company’s 2005 Annual Report to Stockholders (Exhibit 13).

 
Item 6
Item 7
Item 7A
Item 8
         
FirstEnergy
3
4-45
28-31
46-95
OE
2
3-19
10
20-48
Penn
2
3-14
8-9
15-35
CEI
2
3-18
10
19-45
TE
2
3-18
9-10
19-46
JCP&L
2
3-14
7-9
15-40
Met-Ed
2
3-14
8-9
15-36
Penelec
2
3-14
7-9
15-36

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, 2005.

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, 2005. Management’s assessment of the effectiveness of FirstEnergy's internal control over financial reporting, as of December 31, 2005, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report included in FirstEnergy's 2005 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 2005 that have materially affected, or are reasonably likely to materially affect, FirstEnergy's internal control over financial reporting.

- CEI, OE, PENN AND TE

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, 2005.
 
 
27


Changes in Internal Control over Financial Reporting

There were no changes in the registrants' internal control over financial reporting during the fourth quarter of 2005 that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting.

- JCP&L

Evaluation of Disclosure Controls and Procedures

The 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 Chief Executive Officer and Chief Financial Officer concluded that such registrant's disclosure controls and procedures were effective as of December 31, 2005.

Management’s Consideration of the Restatement

In coming to the conclusion that the registrant’s disclosure controls and procedures were effective as of December 31, 2005, management considered, among other things, the restatement related to the tax matter as disclosed in Note 2 to the accompanying consolidated financial statements included in this Form 10-K. Management reviewed and analyzed the Securities and Exchange Commission’s Staff Accounting Bulletin (SAB) No. 99, “Materiality,” paragraph 29 of Accounting Principles Board Opinion No. 28, “Interim Financial Reporting,” and SAB Topic 5F, “Accounting Changes Not Retroactively Applied Due to Immateriality.” Taking into consideration (i) that the restatement adjustments did not have a material impact on the financial statements of prior interim or annual periods taken as a whole; (ii) that the cumulative impact of the restatement adjustments on common stockholder’s equity was not material to the financial statements of prior interim or annual periods; and (iii) that JCP&L decided to restate its previously issued financial statements solely because the cumulative impact of the adjustments, if recorded in the current period, would have been material to the current year’s reported net income, management concluded that these matters individually did not constitute a material weakness.

Changes in Internal Control over Financial Reporting

There were no changes in the registrant’s internal control over financial reporting during the fourth quarter of 2005 that have materially affected, or are reasonably likely to materially affect, the registrant’s internal control over financial reporting.

- 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 ineffective as of December 31, 2005 due to the existence of a material weakness discussed below.

A material weakness is a control deficiency or combination of control deficiencies that results in more than a remote likelihood that a material misstatement of the annual or interim consolidated financial statements will not be prevented or detected. Management identified a material weakness due to deficiencies in the operating effectiveness of internal controls associated with the accuracy of the regulatory accounting for the registrants' NUG contracts. Established accounting procedures were misapplied with respect to Penelec's NUG contract asset, resulting in an inappropriate reduction to deferred NUG costs recoverable through Penelec's CTC and a corresponding understatement of net income. The affected Penelec accounts were properly adjusted as of December 31, 2005. While Met-Ed’s NUG contract position is currently a liability, the material weakness also extends to Met-Ed because the same controls related to the accuracy of the regulatory accounting for NUG contracts also existed for Met-Ed. As a material weakness as described above, this control deficiency could result in a misstatement of the aforementioned accounts that could result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected.

Management is strengthening the effectiveness of internal controls related to regulatory accounting, related to the registrants' NUG contract accounting. Coordination of activities regarding NUG contracts between regulatory affairs and accounting personnel are being enhanced and a more robust review and approval process involving higher-level management is being established. The registrants plan to fully implement the enhancements in the first quarter of 2006.

 
 
28


This material weakness was discussed with the Audit Committee of the Board of Directors and PricewaterhouseCoopers LLP, the registrants' independent registered public accountants.

Changes in Internal Control over Financial Reporting

There were no changes in the registrants' internal control over financial reporting during the fourth quarter of 2005 that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

On February 21, 2006, the Board of Directors approved the recommendation of the Compensation Committee establishing FirstEnergy’s confidential performance and business criteria or Key Performance Indicators (KPIs) for the 2006 performance period. These KPIs are related to various operational and corporate objectives.

Mr. Alexander’s KPIs are based on the achievement of certain levels of earnings per share, free cash flow from operations, customer service excellence, and employee, nuclear and other operational safety measures.

The KPIs established for Messrs. Clark and Marsh and Ms. Vespoli are based on the achievement of certain levels of earnings per share, free cash flow from operations, employee safety, corporate operating measures and contributions to earnings from various strategic initiatives.

The KPIs established for Mr. Grigg are based on the achievement of certain levels of earnings per share, free cash flow from operations, employee safety, corporate operating measures, reliability and generation fleet performance and margin.
 
                On February 21, 2006, FirstEnergy’s Board of Directors approved the award of performance-adjusted restricted stock units (“RSUs’) to the named executive officers (the “Grantees”) under the FirstEnergy Executive and Director Incentive Compensation Plan (the “Plan”). The Plan is applicable to, among others, the company’s senior executive officers including the Grantees. The performance-adjusted restricted stock units are subject to a Restricted Stock Unit Agreement (the “Agreement”) dated March 1, 2006. Under the terms and conditions of the Agreement, the company granted a pre-determined number of RSUs that are subject to adjustment based on the company’s performance as described below.

        The RSUs vest at the end of three years. Dividends accrue on the RSUs during the vesting period and are converted into additional units. The Grantee is credited on the books and records of the company with an amount per unit equal to the amount per share of any cash dividends declared by the Board of Directors on the outstanding common stock of the company. The RSUs will be settled in actual company shares of common stock upon vesting. Additionally, the number of shares awarded at the end of the vesting period may be increased or decreased by 25% based on company performance.

         The company will measure its performance against three key metrics (i.e., earnings per share, safety, and the operational performance index) during the three-year vesting period to determine if the target number of shares that actually vest will be increased or decreased by the 25% increment, or remain at the target level. The annual target performance level relating to each metric for each year will be established by the Compensation Committee in February of that year. The actual performance result for each of the three years will be averaged and compared to the average target level set for each performance metric. Depending upon the results of the comparison for each of the three metrics, the final award may increase, decrease, or remain at the target level.

For example:

·  
If the company’s average annual performance exceeds target on all three measures, 25% additional shares will be awarded at the end of the three-year vesting period;
   
·  
If the company’s average annual performance is below target on all three measures, 25% fewer shares will be awarded at the end of the vesting period; and
   
·  
If the company’s average annual performance exceeds target on some of the measures but is below the target on others, the base number of shares issuable under the RSUs as originally granted will not be increased or decreased.

 
        The Agreement of each Grantee contains share value protection rights that are triggered in the event of a change in control. Under the share value protection provisions, the Grantee is entitled, at vesting, to the highest of three values: the value of the units as of the day of the grant, the value as of the date of the change in control, or the value as of the date the restricted units are paid out by operation of the Plan. If necessary, the share value protection provisions trigger a lump sum cash payment to ensure compliance. The share value protection provisions are not triggered if the Grantee voluntarily terminates employment.

        On February 21, 2006 the Board of Directors approved the award of Performance Shares to the Grantees in accordance with the Plan. The awards are effective January 1, 2006, vest at the end of a three-year cycle and are subject to the terms of the Plan and a performance share agreement, substantially similar to the Agreement described above, including the presence of share value protection provisions. The performance shares are equivalent units of FirstEnergy common stock. Dividends accrue on the performance shares during the vesting period and are converted into additional units. Each Grantee is credited on the books and records of the company with an amount per unit equal to the amount per share of any cash dividends declared by the Board of Directors on the outstanding common stock of the company.

       The performance share units are subject to an adjustment based on FirstEnergy’s total shareholder return relative to peer companies in the EEI Index. Awards can be increased by as much as an additional fifty (50) percent or reduced to zero based on this adjustment. Any awards are paid out in cash at the end of the three-year cycle.

       On February 21, 2006, the Board of Directors approved a discretionary RSU award to Mr. Marsh. Awards of discretionary RSUs vest after five years. Dividends accrue on the RSUs during the vesting period and are converted into additional units. Mr. Marsh is credited on the books and records of the company with an amount per unit equal to the amount per share of any cash dividends declared by the Board of Directors on the outstanding common stock of the company. This RSU award is subject to an underlying restricted stock agreement; substantially similar to the Agreement described above, including the presence of share value protection provisions, except that there is no performance adjustment made to the RSUs.

      Finally, effective February 27, 2006, the Board of Directors approved a Restricted Stock award to Mr. Alexander. This award can vest as early as April 30, 2011, at the discretion of the Board of Directors, but no later than April 30, 2013 and will be paid out in shares of FirstEnergy common stock. Dividends accrue on the underlying shares during the vesting period and are converted into additional shares. Mr. Alexander is credited on the books and records of the company with an amount per share equal to the amount per share of any cash dividends declared by the Board of Directors on the outstanding common stock of the company. The award, like the others, is subject to an agreement, substantially similar to the Agreement described above, including the presence of share value protection provisions.
 
 
29

 
PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

FirstEnergy

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 2006 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 has determined that Ernest J. Novak, Jr., an independent director, is the audit committee financial expert.

FirstEnergy makes available on its website 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 David W. Whitehead, 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 our website 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 24, 2005.

OE, Penn, CEI, TE, JCP&L, Met-Ed and Penelec

A. J. Alexander, R. H. Marsh and R. R. Grigg are the Directors of OE, Penn, CEI, TE, Met-Ed and Penelec. Information concerning these individuals is shown in the “Executive Officers” section of Item 1. S. E. Morgan, C. E. Jones, L. L. Vespoli, B. S. Ewing, M. A. Julian, G. E. Persson and S. C. Van Ness are the Directors of JCP&L.

Mr. Ewing (Age 45) has served as FirstEnergy Service Company’s Vice President - Energy Delivery since 2003. From 1999 to 2003, Mr. Ewing served as Director of Operations Services - Northern Region.

Mr. Julian (Age 49) has served as FirstEnergy Service Company’s Vice President - Energy Delivery since 2003. From 2001 to 2003, Mr. Julian served as Director of Energy Delivery Technical Services. He was Director of Operations Services - Northern Region from 2000 to 2001.

Mrs. Persson (Age 75) has served in the New Jersey Division of Consumer Affairs Elder Fraud Investigation Unit since 1999. She previously served as liaison (Special Assistant Director) between the New Jersey Division of Consumer Affairs and various state boards. Prior to 1995, she was owner and President of Business Dynamics Associated of Red Bank, NJ. Mrs. Persson is a member of the United States Small Business Administration National Advisory Board, the New Jersey Small Business Advisory Council, the Board of Advisors of Brookdale Community College and the Board of Advisors of Georgian Court College.

 
30


Mr. Van Ness (Age 72) has been of Counsel in the firm of Herbert, Van Ness, Cayci & Goodell, PC of Princeton, NJ since 1998. Prior to that he was affiliated with the law firm of Pico, Mack, Kennedy, Jaffe, Perrella and Yoskin of Trenton, NJ since 1990. He is also a director of The Prudential Insurance Company of America.

Information concerning the other Directors of JCP&L is shown in the “Executive Officers” section of Item 1 of this report.

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

FirstEnergy, OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec -

The information required by Items 11, 12 and 13 is incorporated herein by reference to FirstEnergy’s 2006 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, 2005 and 2004 are as follows:

   
Audit Fees(1)
 
Audit-Related Fees(2)
 
Company
 
2005
 
2004
 
2005
 
2004
 
   
(In thousands)
 
OE
 
$
879
 
$
1,036
 
$
-
 
$
-
 
CEI
   
755
   
797
   
-
   
-
 
TE
   
610
   
650
   
-
   
-
 
Penn
   
613
   
624
   
-
   
-
 
JCP&L
   
728
   
810
   
-
   
-
 
Met-Ed
   
597
   
609
   
-
   
-
 
Penelec
   
605
   
595
   
-
   
-
 
Other subsidiaries
   
1,786
   
1,542
   
-
   
18
 
                           
Total FirstEnergy
 
$
6,573
 
$
6,663
 
$
-
 
$
18
 

 
 
(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.
 
 
 
(2)
Assurance and related services related to audits of employee benefit plans.
 
 
Tax and Other Fees
 
There were no other fees billed to FirstEnergy for tax or other services for the years ended December 31, 2005 and December 31, 2004.

Additional information required by this item is incorporated herein by reference to FirstEnergy's 2006 Proxy Statement filed with the SEC pursuant to Regulation 14A.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) 1. Financial Statements

Included in Part II of this report and incorporated herein by reference to the respective company’s 2005 Annual Report to Stockholders (Exhibit 13 below) at the pages indicated.


 
31


 


   
First-
Energy
 
 
OE
 
 
Penn
 
 
CEI
 
 
TE
 
 
JCP&L*
 
 
Met-Ed
 
 
Penelec
 
   
                                   
Management Reports
   
1
   
-
   
-
   
-
   
-
   
-
   
-
   
-
 
Report of Independent Registered Public Accounting Firm
   
2
   
1
   
1
   
1
   
1
   
1
   
1
   
1
 
Statements of Income-Three Years Ended December 31, 2005
    46     
20
    15     19     19     15     15     15  
Balance Sheets-December 31, 2005 and 2004
    47      21     16     20     20      16      16      16  
Statements of Capitalization-December 31, 2005 and 2004
    48-50     22-23     17     21     21      17      17      17  
Statements of Common Stockholders’ Equity-Three Years
Ended December 31, 2005
    51     24     18     22     22      18      18      18  
Statements of Preferred Stock-Three Years Ended
December 31, 2005
    52     24     18     22     22      18      18      18  
Statements of Cash Flows-Three Years Ended December 31, 2005
    53     25     19     23     23      19      19      19  
Statements of Taxes-Three Years Ended December 31, 2005
    54     26     20     24     24      20      20      20  
Notes to Financial Statements
   
55-95
    27-48     21-35     25-45     25-46      21-40      21-36      21-36  
 
* JCP&L is restating its consolidated financial statements for the two years ended December 31, 2004. The revisions are a result of a current tax audit from the State of New Jersey, in which JCP&L became aware that the New Jersey Transitional Energy Facilities Assessment tax is not an allowable deduction for state income tax purposes. See Note 2(I) to JCP&L’s consolidated financial statements for further discussion.

2.  
Financial Statement Schedules

Included in Part IV of this report:

 
First-
Energy
 
OE
 
Penn
 
CEI
 
TE
 
JCP&L
 
Met-Ed
 
Penelec
 
                 
Report of Independent Registered Public Accounting
Firm
68  69  72  70  71  73  74  75 
                 
Schedule - Three Years Ended December 31, 2005:
II - Consolidated Valuation and Qualifying Accounts
76  77  80  78  79  81  82  83 

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 Corp.

Exhibit
Number

3-1
Articles of Incorporation constituting FirstEnergy Corp.’s Articles of Incorporation, dated September 17, 1996. (September 17, 1996 Form 8-K, Exhibit C)
   
3-1(a)
Amended Articles of Incorporation of FirstEnergy Corp. (Registration No. 333-21011, Exhibit (3)-1)
   
3-2
Regulations of FirstEnergy Corp. (September 17, 1996 Form 8-K, Exhibit D)
   
3-2(a)
FirstEnergy Corp. Amended Code of Regulations. (Registration No. 333-21011, Exhibit (3)-2)
   
4-1
Rights Agreement (December 1, 1997 Form 8-K, Exhibit 4.1)
   
4-2
FirstEnergy Corp. to The Bank of New York, Supplemental Indenture, dated November 7, 2001. (2001 Form 10-K, Exhibit 4-2)
   
(C)10-1
FirstEnergy Corp. Executive and Director Incentive Compensation Plan, revised November 15, 1999. (1999 Form 10-K, Exhibit 10-1)
   
(C)10-2
Amended FirstEnergy Corp. Deferred Compensation Plan for Directors, revised November 15, 1999. (1999 Form 10-K, Exhibit 10-2)
   
(C)10-3
Form of Employment, severance and change of control agreement between FirstEnergy Corp. and the following executive officers: L.L. Vespoli, C.B. Snyder, and R.H. Marsh, through December 31, 2005. (1999 Form 10-K, Exhibit 10-3)
   
(C)10-4
FirstEnergy Corp. Supplemental Executive Retirement Plan, amended January 1, 1999. (1999 Form 10-K, Exhibit 10-4)
   
(C)10-5
FirstEnergy Corp. Executive Incentive Compensation Plan. (1999 Form 10-K, Exhibit 10-5)
   
(C)10-6
Restricted stock agreement between FirstEnergy Corp. and A. J. Alexander. (1999 Form 10-K, Exhibit 10-6)
   
(C)10-7
FirstEnergy Corp. Executive and Director Incentive Compensation Plan. (1998 Form 10-K, Exhibit 10-1)

 
32

EXHIBIT
NUMBER


   
(C)10-8
Amended FirstEnergy Corp. Deferred Compensation Plan for Directors, amended February 15, 1999. (1998 Form 10-K, Exhibit 10-2)
   
(C)10-9
Restricted Stock Agreement between FirstEnergy Corp. and A. J. Alexander. (2000 Form 10-K, Exhibit 10-9)
   
(C)10-10
Restricted Stock Agreement between FirstEnergy Corp. and H. P. Burg. (2000 Form 10-K, Exhibit 10-10)
   
(C)10-11
Stock Option Agreement between FirstEnergy Corp. and officers dated November 22, 2000. (2000 Form 10-K, Exhibit 10-11)
   
(C)10-12
Stock Option Agreement between FirstEnergy Corp. and officers dated March 1, 2000. (2000 Form 10-K, Exhibit 10-12)
   
(C)10-13
Stock Option Agreement between FirstEnergy Corp. and director dated January 1, 2000. (2000 Form 10-K, Exhibit 10-13)
   
(C)10-14
Stock Option Agreement between FirstEnergy Corp. and two directors dated January 1, 2001. (2000 Form 10-K, Exhibit 10-14)
   
(C)10-15
Executive and Director Incentive Compensation Plan dated May 15, 2001. (2001 Form 10-K, Exhibit 10-15)
   
(C)10-16
Amended FirstEnergy Corp. Deferred Compensation Plan for Directors, revised September 18, 2000. (2001 Form 10-K, Exhibit 10-16)
   
(C)10-17
Stock Option Agreements between FirstEnergy Corp. and Officers dated May 16, 2001. (2001 Form 10-K, Exhibit 10-17)
   
(C)10-18
Form of Restricted Stock Agreements between FirstEnergy Corp. and Officers. (2001 Form 10-K, Exhibit 10-18)
   
(C)10-19
Stock Option Agreements between FirstEnergy Corp. and One Director dated January 1, 2002. (2001 Form 10-K, Exhibit 10-19)
   
(C)10-20
FirstEnergy Corp. Executive Deferred Compensation Plan. (2001 Form 10-K, Exhibit 10-20)
   
(C)10-21
Executive Incentive Compensation Plan-Tier 2. (2001 Form 10-K, Exhibit 20-21)
   
(C)10-22
Executive Incentive Compensation Plan-Tier 3. (2001 Form 10-K, Exhibit 20-22)
   
(C)10-23
Executive Incentive Compensation Plan-Tier 4. (2001 Form 10-K, Exhibit 10-23)
   
(C)10-24
Executive Incentive Compensation Plan-Tier 5. (2001 Form 10-K, Exhibit 10-24)
   
(C)10-25
Amendment to GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries, effective April 5, 2001. (2001 Form 10-K, Exhibit 10-25)
   
(C)10-26
Form of Amendment, effective November 7, 2001, to GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries, Deferred Remuneration Plan for Outside Directors of GPU, Inc., and Retirement Plan for Outside Directors of GPU, Inc. (2001 Form 10-K, Exhibit 10-26)
   
(C)10-27
GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group, Inc. Employees. (2001 Form 10-K, Exhibit 10-27)
   
(C)10-28
Executive and Director Stock Option Agreement dated June 11, 2002. (2002 Form 10-K, Exhibit 10-28)
   
(C)10-29
Director Stock Option Agreement. (2002 Form 10-K, Exhibit 10-29)
   
(C)10-30
Executive and Director Executive Incentive Compensation Plan, Amendment dated May 21, 2002. (2002 Form 10-K, Exhibit 10-30)
   
(C)10-31
Directors Deferred Compensation Plan, Revised Nov. 19, 2002. (2002 Form 10-K, Exhibit 10-31)


 
33

EXHIBIT
NUMBER


   
(C)10-32
Executive Incentive Compensation Plan 2002. (2002 Form 10-K, Exhibit 10-32)
   
(C)10-33
GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries as amended and restated to reflect amendments through June 3, 1999. (1999 Form 10-K, Exhibit 10-V, File No. 1-6047, GPU, Inc.)
   
(C)10-34
Form of 1998 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries. (1997 Form 10-K, Exhibit 10-Q, File No. 1-6047, GPU, Inc.)
   
(C)10-35
Form of 1999 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries. (1999 Form 10-K, Exhibit 10-W, File No. 1-6047, GPU, Inc.)
   
(C)10-36
Form of 2000 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries. (2000 Form 10-K, Exhibit 10-W, File No. 1-6047, GPU, Inc.)
   
(C)10-37
Deferred Remuneration Plan for Outside Directors of GPU, Inc. as amended and restated effective August 8, 2000. (2000 Form 10-K, Exhibit 10-O, File No. 1-6047, GPU, Inc.)
   
(C)10-38
Retirement Plan for Outside Directors of GPU, Inc. as amended and restated as of August 8, 2000. (2000 Form 10-K, Exhibit 10-N, File No. 1-6047, GPU, Inc.)
   
(C)10-39
Forms of Estate Enhancement Program Agreements entered into by certain former GPU directors. (1999 Form 10-K, Exhibit 10-JJ, File No. 1-6047, GPU, Inc.)
   
(C)10-40
Deferred Compensation Plan for Outside Directors, effective November 7, 2001. (Exhibit 4(f), Form S-8, File No. 333-101472)
   
(C)10-41
Employment Agreement between FirstEnergy and an officer dated July 20, 2004. (September 30, 2004 Form 10-Q, Exhibit 10-41)
   
(C)10-42
Stock Option Agreement between FirstEnergy and an officer dated August 20, 2004. (September 30, 2004 Form 10-Q, Exhibit 10-42)
   
(C)10-43
Restricted Stock Agreement between FirstEnergy and an officer dated August 20, 2004. (September 30, 2004 Form 10-Q, Exhibit 10-43)
   
(C)10-44
Executive Bonus Plan between FirstEnergy and Officers dated October 31, 2004. (September 30, 2004 Form 10-Q, Exhibit 10-44)
   
(C)10-45
Form of Employment, Severance, and Change of Control Agreement, between FirstEnergy and A. J. Alexander. (2004 Form 10-K, Exhibit 10-47)
   
(C)10-46
Form of Employment, Severance, and Change of Control Agreement, Tier 1, between FirstEnergy and the following executive officers: C.B. Snyder, L.L. Vespoli, and R.H. Marsh (effective January 1, 2006). (2004 Form 10-K, Exhibit 10-48)
   
(C)10-47
Form of Employment, Severance, and Change of Control Agreement, Tier 1, between FirstEnergy and the following executive officers: L.M. Cavalier, M.T. Clark, and R.R. Grigg. (2004 Form 10-K, Exhibit 10-49)
   
(C)10-48
Form of Employment, Severance, and Change of Control Agreement, Tier 2, between FirstEnergy and the following executive officers: K.J. Keough and K.W. Dindo (effective January 1, 2006). (2004 Form 10-K, Exhibit 10-50)
   
(C)10-49
Form of Employment, Severance, and Change of Control Agreement, Tier 2, between FirstEnergy and G. L. Pipitone. (2004 Form 10-K, Exhibit 10-51)


 
34

EXHIBIT
NUMBER


   
(C)10-50
Executive and Director Incentive Compensation Plan, Amendment dated January 18, 2005. (2004 Form 10-K, Exhibit 10-52)
   
(C)10-51
Form of Restricted Stock Agreements, between FirstEnergy and Officers. (2004 Form 10-K, Exhibit 10-53)
   
(C)10-52
Form of Restricted Stock Unit Agreements (Performance Adjusted), between FirstEnergy and Officers. (2004 Form 10-K, Exhibit 10-54)
   
(C)10-53
Form of Restricted Stock Agreement, between FirstEnergy and an officer. (2004 Form 10-K, Exhibit 10-55)
   
10-54
Notice of Termination Tolling Agreement, Restated Partial Requirements Agreement (September 2005 10-Q, Exhibit 10.1)
   
10-55
Agreement by and between FirstEnergy Generation Corp. and Bechtel Power Corporation dated August 26, 2005. (September 2005 10-Q, Exhibit 10.2)
   
10-56
Consent Decree dated as of March 18, 2005. (Form 8-K dated March 18, 2005, Exhibit 10.1.)
   
10-57
Deferred Prosecution Agreement entered into January 20, 2006 among FirstEnergy Nuclear Operating Company, U.S. Attorney's Office for the Northern District of Ohio and the Environmental Crimes Section of the Environment and Natural Resources Division of the Department of Justice. (Form 8-K dated January 20, 2006, Exhibit 99.2)
   
      (A)(D)10-58
Form of Guaranty Agreement dated as of December 16, 2005 between FirstEnergy Corp. and FirstEnergy Solutions Corp. in Favor of Barclays Bank PLC as Adminstrative Agent for the Banks.
   
      (A)(D)10-59
Form of Trust Indenture dated as of December 1, 2005 between Ohio Water Development Authority and JP Morgan Trust Company related to issuance of FirstEnergy Nuclear Generation Corp. pollution control revenue refunding bonds.
   
(A)10-60
GENCO Power Supply Agreement dated as of October 14, 2005 between FirstEnergy Generation Corp. (Seller) and FirstEnergy Solutions Corp. (Buyer).
   
(A)10-61
Nuclear Power Supply Agreement dated as of October 14, 2005 between FirstEnergy Nuclear Generation Corp. (Seller) and FirstEnergy Solutions Corp. (Buyer).
   
      (A)(D)10-62
Form of Letter of Credit and Reimbursement Agreement Dated as of December 16, 2005 among FirstEnergy Nuclear Generation Corp., and the Participating Banks and Barclays Bank PLC.
   
      (A)(D)10-63
Form of Waste Water Facilities and Solid Waste Facilities Loan Agreement Between Ohio Water Development Authority and FirstEnergy Nuclear Generation Corp., Dated as of December 1, 2005.
   
(A)10-64
Nuclear Sale/Leaseback Power Supply Agreement dated as of October 14, 2005 between Ohio Edison Company and The Toledo Edison Company (Sellers) and FirstEnergy Nuclear Generation Corp. (Buyer)
   
(A)10-65
Mansfield Power Supply Agreement dated as of October 14, 2005 between The Cleveland Electric Illuminating Company and The Toledo Edison Company (Sellers) and FirstEnergy Generation Corp. (Buyer)
   
(A)10-66
Power Supply Agreement dated as of October 31, 2005 between FirstEnergy Solutions Corp. (Seller) and the FirstEnergy Operating Companies - OE, CEI and TE (Buyers)
   
(A)10-67
Electric Power Supply Agreement dated as of October 31, 2005 between FirstEnergy Solutions Corp. (Seller) and Pennsylvania Power Company (Buyer).
   
(A)12.1
Consolidated fixed charge ratios.


 
35

EXHIBIT
NUMBER


   
(A)13
FirstEnergy 2005 Annual Report to Stockholders. (Only those portions expressly incorporated by reference in this Form 10-K are to be deemed “filed” with the SEC.)
   
(A)21
List of Subsidiaries of the Registrant at December 31, 2005.
   
(A)23
Consent of Independent Registered Public Accounting Firm.
   
(A)31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e) (FirstEnergy, OE, CEI, TE, Penn, Met-Ed and Penelec).
   
(A)31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e) (FirstEnergy, OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec).
   
(A)32.1
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350 (FirstEnergy, OE, CEI, TE, Penn, Met-Ed and Penelec).
   
(A)
Provided herein in electronic format as an exhibit.
   
(C)
Management contract or compensatory plan contract or arrangement filed pursuant to Item 601 of Regulation S-K.
   
            (D) Four substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to four other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority, the Ohio Air Quality Authority and Beaver County Industrial Development Authority, Pennsylvania, relating to pollution control notes of FirstEnergy Nuclear Generation Corp.

(B) 3. Exhibits - Ohio Edison Company (OE)

2-1
Agreement and Plan of Merger, dated as of September 13, 1996, between Ohio Edison Company (OE) and Centerior Energy Corporation. (September 17, 1996 Form 8-K, Exhibit 2-1)
   
3-1
Amended Articles of Incorporation, Effective June 21, 1994, constituting OE’s Articles of Incorporation. (1994 Form 10-K, Exhibit 3-1).
   
3-2
Amendment to Articles of Incorporation, Effective November 12, 1999 (2004 Form 10-K, Exhibit 3-2).
   
3-3
Amended and Restated Code of Regulations, amended March 15, 2002. (2001 Form 10-K, Exhibit 3-2).
   
(B)4-1
Indenture dated as of August 1, 1930 between OE and Bankers Trust Company (now the Bank of New York), as Trustee, as amended and supplemented by Supplemental Indentures:


       
Incorporated by
       
Reference to
Dated as of
 
File Reference
 
Exhibit No.
March 3, 1931
 
2-1725
 
B1, B-1(a),B-1(b)
November 1, 1935
 
2-2721
 
B-4
January 1, 1937
 
2-3402
 
B-5
September 1, 1937
 
Form 8-A
 
B-6
June 13, 1939
 
2-5462
 
7(a)-7
August 1, 1974
 
Form 8-A, August 28, 1974
 
2(b)
July 1, 1976
 
Form 8-A, July 28, 1976
 
2(b)
December 1, 1976
 
Form 8-A, December 15, 1976
 
2(b)
June 15, 1977
 
Form 8-A, June 27, 1977
 
2(b)
Supplemental Indentures:
       
September 1, 1944
 
2-61146
 
2(b)(2)
April 1,