10-K 1 form_10k.htm FORM 10K DATED DECEMBER 31, 2006 Unassociated Document


 

 
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, 2006
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
 
     
1-3141
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
The Cleveland Electric Illuminating Company
 
9% Cumulative Trust Preferred Securities,
$25 per preferred security
 
New York Stock Exchange

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

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

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

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.

(  )
FirstEnergy Corp.
(X)
Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company.

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

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

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

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

 
                  Securities registered pursuant to Section 12(g) of the Act:
 
                   None
 

 



State the aggregate market value of the common stock held by non-affiliates of the registrants: FirstEnergy Corp., $17,795,189,814 as of June 30, 2006; 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 February 27, 2007
     
FirstEnergy Corp., $0.10 par value
 
319,205,517
Ohio Edison Company, no par value
 
60
The Cleveland Electric Illuminating Company, no par value
 
67,930,743
The Toledo Edison Company, $5 par value
 
29,402,054
Jersey Central Power & Light Company, $10 par value
 
15,009,335
Metropolitan Edison Company, no par value
 
859,500
Pennsylvania Electric Company, $20 par value
 
5,290,596

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

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, 2006 (Pages 3-104)
 
Part II
     
Proxy Statement for 2007 Annual Meeting of Stockholders
   
to be held May 15, 2007
 
Part III

This combined Form 10-K is separately filed by FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant, except that information relating to any of the six 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 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
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
Bechtel
Bechtel Power Corporation
BGS
Basic Generation Service
B&W
Babcock & Wilcox Company
CAIR
Clean Air Interstate Rule
CAL
Confirmatory Action Letter
CAMR
Clean Air Mercury 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
EPRI
Electric Power Research Institute
ERO
Electric Reliability Organization
FERC
Federal Energy Regulatory Commission
FMB
First Mortgage Bonds
GHG
Greenhouse Gases
MISO
Midwest Independent Transmission System Operator, Inc.
MOU
Memorandum of Understanding
MW
Megawatts
NAAQS
National Ambient Air Quality Standards
NERC
North American Electric Reliability Corporation
NEIL
Nuclear Electric Insurance Limited
NJBPU
New Jersey Board of Public Utilities
NOV
Notices of Violation
NOX
Nitrogen Oxide
NRC
Nuclear Regulatory Commission
NUG
Non-Utility Generator
NUGC
Non-Utility Generation Charge

i

 
GLOSSARY OF TERMS, Cont'd

 
NYSE
New York Stock Exchange
OCC
Ohio Consumers' Counsel
OVEC
Ohio Valley Electric Corporation
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
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"
SFAS 144
SFAS No. 144, "Accounting for the Impairment of Disposal of Long-Lived Assets"
SO2
Sulfur Dioxide
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
2
Regulatory Accounting
3
Reliability Initiatives
3
PUCO Rate Matters
5
PPUC Rate Matters
6
NJBPU Rate Matters
8
FERC Rate Matters
10
Capital Requirements
11
Nuclear Regulation
14
Nuclear Insurance
14
Environmental Matters
15
Clean Air Act Compliance
15
National Ambient Air Quality Standards
16
Mercury Emissions
16
W. H. Sammis Plant
17
Climate Change
17
Clean Water Act
17
Regulation of Hazardous Waste
18
Fuel Supply
18
System Capacity and Reserves
19
Regional Reliability
19
Competition
19
Research and Development
20
Executive Officers
21
Employees
22
FirstEnergy Website
22
   
Item 1A. Risk Factors
    22
   
Item 1B. Unresolved Staff Comments
    30
   
Item 2.    Properties
30
   
Item 3.    Legal Proceedings
32
   
Item 4.    Submission of Matters to a Vote of Security Holders
32
   
Part II
 
Item 5.    Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities
32
   
Item 6.    Selected Financial Data
33
   
Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations
33
   
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
33
   
Item 8.    Financial Statements and Supplementary Data
33
   
Item 9.    Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
33
   
Item 9A. Controls and Procedures
33
   
Item 9B. Other Information
34
   
Part III
 
Item 10. Directors and Executive Officers of the Registrant
34
   
Item 11. Executive Compensation
35
   
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
35
   
Item 13. Certain Relationships and Related Transactions
35
   
Item 14. Principal Accounting Fees and Services
35
   
Part IV
 
Item 15. Exhibits, Financial Statement Schedules
36








PART I
ITEM 1. BUSINESS

The Company

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

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 11.3 million.

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

OE owns all of Penn's outstanding common stock. Penn was organized under the laws of the Commonwealth of Pennsylvania in 1930 and owns property and does business as an electric public utility in that state. Penn is also authorized to do business in the State of Ohio (see Item 2 - Properties). Penn furnishes electric service to communities in a 1,100 square mile area of western Pennsylvania. The area it serves has a population of approximately 0.3 million. Penn complies with the regulations, orders, policies and practices prescribed by the FERC and PPUC.  

CEI was organized under the laws of the State of Ohio in 1892 and does business as an electric public utility in that state. CEI engages in the distribution and sale of electric energy in an area of approximately 1,600 square miles in northeastern Ohio. The area it serves has a population of approximately 1.9 million. CEI complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PUCO.

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

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. 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 FERC, NERC and other applicable regulatory agencies to ensure reliable service to FirstEnergy's customers (see Transmission Rate Matters for a discussion of ATSI's participation in 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 3,200 square miles of northern, western and east central New Jersey. The area it serves has a population of approximately 2.6 million. JCP&L complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and the NJBPU.

Met-Ed was organized under the laws of the Commonwealth of Pennsylvania in 1922 and owns property and does business as an electric public utility in that state. Met-Ed provides transmission and distribution services in 3,300 square miles of eastern and south central Pennsylvania. The area it serves has a population of approximately 1.2 million. Met-Ed complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PPUC.

Penelec was organized under the laws of the Commonwealth of Pennsylvania in 1919 and owns property and does business as an electric public utility in that state. Penelec provides transmission and distribution services in 17,600 square miles of western, northern and south central Pennsylvania. The area it serves has a population of approximately 1.7 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. Penelec complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PPUC.

1



FES was organized under the laws of the State of Ohio in 1997 and provides energy-related products and services and through its subsidiaries, FGCO and NGC, owns and operates FirstEnergy's non-nuclear generation facilities and owns FirstEnergy's nuclear generation facilities, respectively (see Generation Asset Transfers below). FENOC was organized under the laws of the State of Ohio in 1998 and operates and maintains nuclear generating facilities. NGC and FENOC comply with the regulations, orders, policies and practices prescribed by the NRC. FESC provides legal, financial and other corporate support services to affiliated FirstEnergy companies.

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
 
                   In 2005, the Ohio Companies and Penn entered into certain agreements implementing a series of intra-system generation asset transfers that were completed in the fourth quarter of 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 ownership in the nuclear generation assets to NGC through, in the case of OE and Penn, an asset spin-off by way of dividend and, in the case of CEI and TE, a sale at net book value.
 
                   On December 28, 2006, the NRC approved the transfer of ownership in NGC from FirstEnergy to FES. Effective December 31, 2006, NGC became a wholly owned subsidiary of FES and second tier subsidiary of FirstEnergy. FENOC continues to operate and maintain the nuclear generation assets.
 
                   These transactions were 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 contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants.

Divestitures
 
                   In 2006, FirstEnergy sold its remaining FSG subsidiaries (Roth Bros., Hattenbach, Dunbar, Edwards and RPC) for an aggregate net after-tax gain of $2.2 million. Based on SFAS 144, Hattenbach, Dunbar, Edwards, and RPC are accounted for as discontinued operations as of December 31, 2006. Roth Bros. did not meet the criteria for classification as discontinued operations as of December 31, 2006.
 
               In March 2006, FirstEnergy sold 60% of its interest in MYR for an after-tax gain of $0.2 million. In June 2006, as part of the March 2006 agreement, FirstEnergy sold an additional 1.67% interest. As a result of the March sale, FirstEnergy deconsolidated MYR in the first quarter of 2006 and accounted for its remaining interest under the equity method. In November 2006, FirstEnergy sold the remaining 38.33% interest in MYR for an after-tax gain of $8.6 million. In accordance with SFAS 144, the income for the time period that MYR was accounted for as an equity method investment has not been included in discontinued operations; however, results for all reporting periods prior to the initial sale in March 2006, including the portion of 2006 prior to the sale are reported as discontinued operations.

Utility Regulation
 
                  On August 8, 2005 President Bush signed into law the EPACT. The EPACT repealed PUHCA effective February 2006. PUHCA imposed financial and operational restrictions on many aspects of FirstEnergy's business. Some of PUHCA's consumer protection authority was transferred to the FERC and state utility commissions. The EPACT also provides for tax credits for the development of certain clean coal and emissions technologies.

2


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 net 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.

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

3


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

The EPACT provides for the creation of an ERO to establish and enforce reliability standards for the bulk power system, subject to FERC's review. On February 3, 2006, the FERC adopted a rule establishing certification requirements for the ERO, as well as regional entities envisioned to assume compliance monitoring and enforcement responsibility for the new reliability standards. The FERC issued an order on rehearing on March 30, 2006, providing certain clarifications and essentially affirming the rule.
 
                   The NERC has been preparing the implementation aspects of reorganizing its structure to meet the FERC's certification requirements for the ERO. The NERC made a filing with the FERC on April 4, 2006 to obtain certification as the ERO and to obtain FERC approval of pro forma delegation agreements with regional reliability organizations (regional entities). The new FERC rule referred to above, further provides for reorganizing regional entities that would replace the current regional councils and for rearranging their relationship with the ERO. The "regional entity" may be delegated authority by the ERO, subject to FERC approval, for compliance and enforcement of reliability standards adopted by the ERO and approved by the FERC. The ERO filing was noticed on April 7, 2006 and comments and reply comments were filed in May, June and July 2006. On July 20, 2006, the FERC certified the NERC as the ERO to implement the provisions of Section 215 of the Federal Power Act and directed the NERC to make compliance filings addressing governance and non-governance issues and the regional delegation agreements. On September 18, 2006 and October 18, 2006, NERC submitted compliance filings addressing the governance and non-governance issues identified in the FERC ERO Certification Order, dated July 20, 2006. On October 30, 2006, the FERC issued an order accepting most of NERC's governance filings. On January 18, 2007, the FERC issued an order largely accepting NERC's compliance filings addressing non-governance issues, subject to an additional compliance filing requirement.

On April 4, 2006, NERC also submitted a filing with the FERC seeking approval of mandatory reliability standards, as well as for approval with the relevant Canadian authorities. These reliability standards are based, with some modifications and additions, on the current NERC Version 0 reliability standards. The reliability standards filing was subsequently evaluated by the FERC on May 11, 2006, leading to the FERC staff's release of a preliminary assessment that cited many deficiencies in the proposed reliability standards. The NERC and industry participants filed comments in response to the Staff's preliminary assessment. The FERC held a technical conference on the proposed reliability standards on July 6, 2006. The FERC issued a NOPR on the proposed reliability standards on October 20, 2006. In the NOPR, the FERC proposed to approve 83 of the 107 reliability standards and directed NERC to make technical improvements to 62 of the 83 standards approved. The 24 standards that were not approved remain pending at the FERC awaiting further clarification and filings by the NERC and regional entities. The FERC also provided additional clarification within the NOPR regarding the proposed application of final standards and guidance with regard to technical improvements of the standards. On November 15, 2006, NERC submitted several revised reliability standards and three new proposed reliability standards. Interested parties were provided the opportunity to comment on the NOPR (including the revised standards submitted by NERC in November) by January 3, 2007. Numerous parties, including FirstEnergy, filed comments on the NOPR on January 3, 2007. Mandatory reliability standards enforceable with penalties are expected to be in place by the summer of 2007. In a separate order issued October 24, 2006, the FERC approved NERC's 2007 budget and business plan subject to certain compliance filings.

   On November 29, 2006, NERC submitted an additional compliance filing with the FERC regarding the Compliance Monitoring and Enforcement Program (CMEP) along with the proposed Delegation Agreements between the ERO and the regional reliability entities. The FERC provided opportunity for interested parties to comment on the CMEP by January 10, 2007. We, as well as other parties, moved to intervene and submitted responsive comments on January 10, 2007. This filing is pending before the FERC.
 
                   The ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils completed the consolidation of these regions into a single new regional reliability organization known as ReliabilityFirst Corporation. ReliabilityFirst began operations as a regional reliability council under NERC on January 1, 2006 and on November 29, 2006 filed a proposed Delegation Agreement with NERC to obtain certification consistent with the final rule as a "regional entity" under the ERO. All of FirstEnergy's facilities are located within the ReliabilityFirst region.

4


 
                   On May 2, 2006, the NERC Board of Trustees adopted eight new cyber security standards that replaced interim standards put in place in the wake of the September 11, 2001 terrorist attacks, and thirteen additional reliability standards. The security standards became effective on June 1, 2006, and the remaining standards will become effective throughout 2006 and 2007. NERC filed these proposed standards with the FERC and relevant Canadian authorities for approval. The cyber security standards were not included in the October 20, 2006 NOPR and are being addressed in a separate FERC docket. On December 11, 2006, the FERC Staff provided its preliminary assessment of these proposed mandatory reliability standards and again cited various deficiencies in the proposed standards, providing interested parties with the opportunity to comment on the assessment by February 12, 2007.
 
                   FirstEnergy believes it is in compliance with all current NERC reliability standards. However, based upon a review of the October 20, 2006 NOPR, it appears that the FERC will adopt more strict reliability standards than those contained in the current NERC 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 October 21, 2003, the Ohio Companies filed their RSP case with the PUCO. On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to the PUCO's concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming the PUCO's order in all respects, except it remanded back to the PUCO the matter of ensuring the availability of sufficient means for customer participation in the marketplace. The RSP contained a provision that permitted the Ohio Companies to withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies have 30 days from the final order or decision to provide notice of termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding on Remand. In their Request, the Ohio Companies provided notice of termination to those provisions of the RSP subject to termination, subject to being withdrawn, and also set forth a framework for addressing the Supreme Court of Ohio's findings on customer participation. If the PUCO approves a resolution to the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies' termination will be withdrawn and considered to be null and void. On July 26, 2006, the PUCO issued an Entry directing the Ohio Companies to file a plan in a new docket to address the Court's concern. The Ohio Companies filed their RSP Remand CBP on September 29, 2006. Initial comments were filed on January 12, 2007 and reply comments were filed on January 29, 2007. In their reply comments the Ohio Companies described the highlights of a new tariff offering they would be willing to make available to customers that would allow customers to purchase renewable energy certificates associated with a renewable generation source, subject to PUCO approval. No further proceedings are scheduled at this time.
 
                   The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP filed on September 9, 2005. Major provisions of the RCP include:

·
Maintaining the existing level of base distribution rates through December 31, 2008 for OE and TE, and April 30, 2009 for CEI;
   
·
Deferring and capitalizing for future recovery (over a 25-year period) 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;
   
·
Adjusting 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 and as of December 31, 2010 for CEI;
   
·
Reducing 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
   
·
Recovering increased fuel costs (compared to a 2002 baseline) 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 (for recovery over a 25-year period) increased fuel costs above the amount collected through the fuel recovery mechanism.


5


 
                   On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies' RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. On January 10, 2006, the Ohio Companies filed a Motion for Clarification seeking clarity on a number of issues. 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 PUCO granted the Ohio Companies' requests to:

 
   ·
Recognize fuel and distribution deferrals commencing January 1, 2006;
     
 
   ·
Recognize distribution deferrals on a monthly basis prior to review by the PUCO Staff;
     
 
   ·
Clarify that the types of distribution expenditures included in the Supplemental Stipulation may be deferred; and
   
 
   ·
Clarify that distribution expenditures do not have to be "accelerated" in order to be deferred.
 
                   The PUCO approved the Ohio Companies' methodology for determining distribution deferral amounts, but denied the Motion in that the PUCO Staff must verify the level of distribution expenditures contained in current rates, as opposed to simply accepting the amounts contained in the Ohio Companies' Motion. On February 3, 2006, several other parties filed applications for rehearing, which the PUCO denied on March 1, 2006. Two of these parties subsequently filed notices of appeal with the Supreme Court of Ohio. The Ohio Supreme Court scheduled this case for oral argument on February 27, 2007. On January 31, 2007, the Ohio Companies filed a stipulation which, among other matters and subject to PUCO approval, affirmed that the supplemental stipulation in the RCP would be implemented. This stipulation was approved by the PUCO on February 14, 2007.
 
           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 parties reached a settlement agreement that was approved by the PUCO on August 31, 2005. The incremental transmission and ancillary service revenues recovered from January 1 through June 30, 2006 were approximately $54 million. That amount included the recovery of a portion of the 2005 deferred MISO expenses as described below. On April 27, 2006, the Ohio Companies filed the annual update rider to determine revenues ($124 million) from July 2006 through June 2007. The filed rider went into effect on July 1, 2006.

The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period 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. On January 20, 2006, the OCC sought rehearing of the PUCO's approval of the recovery of deferred costs through the rider during the period January 1, 2006 through June 30, 2006. The PUCO denied the OCC's application on February 6, 2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. On March 27, 2006, the OCC filed a motion to consolidate this appeal with the deferral appeals discussed above and to postpone oral arguments in the deferral appeal until after all briefs are filed in this most recent appeal of the rider recovery mechanism. On March 20, 2006, the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of the Ohio Companies' case with a similar case involving Dayton Power & Light Company. Oral arguments were heard on May 10, 2006. On November 29, 2006, the Ohio Supreme Court issued its opinion upholding the PUCO's determination that the Ohio Companies may defer transmission and ancillary service related costs incurred on and after December 30, 2004. The Ohio Supreme Court also determined that the PUCO erred when it denied the OCC intervention, but further ruled that such error did not prejudice OCC and, therefore, the Ohio Supreme Court did not reverse or remand the PUCO on this ground. The Ohio Supreme Court also determined that the OCC's appeal was not premature. No party filed a motion for reconsideration with the Ohio Supreme Court.

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 May 4, 2006, the PPUC consolidated the merger savings proceeding with the April 10, 2006 comprehensive rate filing proceeding discussed below. On January 11, 2007, the PPUC entered an order in that rate filing proceeding and determined that no merger savings from prior years should be considered in determining customers' rates.

6


           On January 12, 2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005. Met-Ed and Penelec sought to consolidate this proceeding (and modified their request to provide deferral of 2006 transmission-related costs only) with the comprehensive rate filing made on April 10, 2006, described below. On May 4, 2006, the PPUC approved the modified request.
 
           Met-Ed and Penelec have been purchasing a portion of their PLR requirements from FES through a partial requirements wholesale power sales agreement and various amendments. Under these agreements, FES retained the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec. The FES agreements have reduced Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR capacity and energy costs during the term of these agreements with FES.
 
           On April 7, 2006, the parties entered into a Tolling Agreement that arose from FES' notice to Met-Ed and Penelec that FES elected to exercise its right to terminate the partial requirements agreement effective midnight December 31, 2006. On November 29, 2006, Met-Ed, Penelec and FES agreed to suspend the April 7 Tolling Agreement pending resolution of the PPUC's proceedings regarding the Met-Ed and Penelec Transition Rate cases filed April 10, 2006, described below. Separately, on September 26, 2006, Met-Ed and Penelec successfully conducted a competitive RFP for a portion of their PLR obligation for the period December 1, 2006 through December 31, 2008. FES was one of the successful bidders in that RFP process and on September 26, 2006 entered into a Supplier Master Agreement to supply a certain portion of Met-Ed's and Penelec's PLR requirements at market prices that substantially exceed the fixed price in the partial requirements agreements.
 
           Based on the outcome of the Transition Rate filing, as described below, Met-Ed, Penelec and FES agreed to restate the partial requirements power sales agreement effective January 1, 2007. The restated agreement incorporates the same fixed price for residual capacity and energy supplied by FES as in the prior arrangements between the parties, and automatically extends for successive one year terms unless any party gives 60 days' notice prior to the end of the year. The restated agreement allows Met-Ed and Penelec to sell the output of NUG generation to the market and requires FES to provide energy at fixed prices to replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec to satisfy their PLR obligations. The parties have also separately terminated the Tolling, Suspension and Supplier Master agreements in connection with the restatement of the partial requirements agreement. Accordingly, the energy that would have been supplied under the Master Supplier Agreement will now be provided under the restated partial requirements agreement.
 
           If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for its fixed income securities. Based on the PPUC's January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed's and Penelec's generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC.

Met-Ed and Penelec made a comprehensive rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals was approved, the filing would have increased annual revenues by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market priced power procured through a CBP as the amount of supply provided under the then existing FES agreement is phased out in accordance with the April 7, 2006 Tolling Agreement described above. Met-Ed and Penelec also requested approval of the January 12, 2005 petition for the deferral of transmission-related costs discussed above, but only for those costs incurred during 2006. In this rate filing, Met-Ed and Penelec also requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider similar to that implemented in Ohio. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. Hearings were held in late August 2006 and briefing occurred in September and October. The ALJs issued their Recommended Decision on November 2, 2006.

7



   The PPUC entered its Opinion and Order in the rate filing proceeding on January 11, 2007. The Order approved the recovery of transmission costs, including the 2006 deferral, and determined that no merger savings from prior years should be considered in determining customers' rates. The request for increases in generation supply rates was denied as were the requested changes in NUG expense recovery and Met-Ed's non-NUG stranded costs. The order decreased Met-Ed's and Penelec's distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission expenses and the 2006 transmission deferral. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million). Met-Ed and Penelec filed a Petition for Reconsideration on January 26, 2007 on the issues of consolidated tax savings and rate of return on equity. Other parties filed Petitions for Reconsideration on transmission congestion, transmission deferrals and rate design issues. The PPUC on February 8, 2007 entered an order granting Met-Ed's, Penelec's and the other parties' petitions for procedural purposes. Due to that ruling, the period for appeals to the Commonwealth Court is tolled until 30 days after the PPUC enters a subsequent order ruling on the substantive issues raised in the petitions.

   As of December 31, 2006, 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 were $303 million and $70 million, respectively. Penelec's $70 million deferral is subject to final resolution of an IRS settlement associated with NUG trust fund proceeds. During the PPUC's annual audit of Met-Ed's and Penelec's NUG stranded cost balances in 2006, it noted a modification to the NUG purchased power stranded cost accounting methodology made by Met-Ed and Penelec. On August 18, 2006, a PPUC Order was entered requiring Met-Ed and Penelec to reflect the deferred NUG cost balances as if the stranded cost accounting methodology modification had not been implemented. As a result of the PPUC's Order, Met-Ed recognized a pre-tax charge of approximately $10.3 million in the third quarter of 2006, representing incremental costs deferred under the revised methodology in 2005. Met-Ed and Penelec continue to believe that the stranded cost accounting methodology modification is appropriate and on August 24, 2006 filed a petition with the PPUC pursuant to its Order for authorization to reflect the stranded cost accounting methodology modification effective January 1, 1999. Hearings on this petition are scheduled for late February 2007. It is not known when the PPUC may issue a final decision in this matter.

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

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 NUGC rates and market sales of NUG energy and capacity. As of December 31, 2006, the accumulated deferred cost balance totaled approximately $369 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. On June 8, 2006, the NJBPU approved JCP&L's request to issue securitization bonds associated with BGS stranded cost deferrals. On August 10, 2006, JCP&L Transition Funding II, a wholly owned subsidiary of JCP&L, issued $182 million of transition bonds with a weighted average interest rate of 5.5%.

On December 2, 2005, JCP&L filed its request for recovery of $165 million of actual above-market NUG costs incurred from August 1, 2003 through October 31, 2005 and forecasted above-market NUG costs for November and December 2005. On February 23, 2006, JCP&L filed updated data reflecting actual amounts through December 31, 2005 of $154 million of costs incurred since July 31, 2003. On July 18, 2006, JCP&L further requested an additional $14 million of costs that had been eliminated from the securitized amount. A Stipulation of Settlement was signed by all parties, approved by the ALJ and adopted by the NJBPU in its Order dated December 6, 2006. The Order approves an annual $110 million increase in NUGC rates designed to recover deferred costs incurred since August 1, 2003, and a portion of costs incurred prior to August 1, 2003 that were not securitized. The Order requires that JCP&L absorb any net annual operating losses associated with the Forked River Generating Station. In the Settlement, JCP&L also agreed not to seek an increase to the NUGC to become effective before January 2010, unless the deferred balance exceeds $350 million any time after June 30, 2007.
 
 
8

 
         Reacting to the higher closing prices of the 2006 BGS fixed rate auction, the NJBPU, on March 16, 2006, initiated a generic proceeding to evaluate the auction process and potential options for the future. On April 6, 2006, initial comments were submitted. A public meeting was held on April 21, 2006 and a legislative-type hearing was held on April 28, 2006. On June 21, 2006, the NJBPU approved the continued use of a descending block auction for the Fixed Price Residential Class. JCP&L filed its 2007 BGS company specific addendum on July 10, 2006. On October 27, 2006, the NJBPU approved the auction format to procure the 2007 Commercial Industrial Energy Price as well as the specific rules for both the Fixed Price and Commercial Industrial Energy Price auctions. These rules were essentially unchanged from the prior auctions.

           In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DRA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to the Ratepayer Advocate's comments. A schedule for further NJBPU proceedings has not yet been set.
 
           On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that would prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. Comments on the alternative proposal were submitted on June 15, 2006. On November 3, 2006, the NJPBU Staff circulated a revised draft proposal to interested stakeholders.
 
                   New Jersey statutes require that the state periodically undertake a planning process, known as the Energy Master Plan (EMP), to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor's Office and the Governor's Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments.
 
                   In October 2006 the current EMP process was initiated with the issuance of a proposed set of objectives which, as to electricity, included the following:
 
  ·  Reduce the total projected electricity demand by 20% by 2020;
 
  ·       Meet 22.5% of the State's electricity needs with renewable energy resources by that date;
  
  ·  Reduce air pollution related to energy use;
 
  ·  Encourage and maintain economic growth and development;

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

 · 
      Unit prices for electricity should remain no more than +5% of the regional average price (region includes New York, New Jersey, Pennsylvania, Delaware, Maryland 
      and the District of Columbia); and
 
      ·  Eliminate transmission congestion by 2020.
 
           Comments on the objectives and participation in the development of the EMP have been solicited and a number of working groups have been formed to attain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. Public stakeholder meetings were held in the fall of 2006 and in early 2007, and further public meetings are expected in the summer of 2007. A final draft of the EMP is expected to be presented to the Governor in the fall of 2007 with further public hearings anticipated in early 2008. At this time FirstEnergy cannot predict the outcome of this process nor determine its impact.
 
 
9


FERC Rate Matters

On March 28, 2006, ATSI and MISO filed with the FERC a request to modify ATSI's Attachment O formula rate to include revenue requirements associated with recovery of deferred Vegetation Management Enhancement Program (VMEP) costs. ATSI estimated that it may defer approximately $54 million of such costs over a five-year period. Approximately $42 million has been deferred as of December 31, 2006. The effective date for recovery was June 1, 2006. The FERC conditionally approved the filing on May 22, 2006, and on July 14, 2006 FERC accepted the ATSI compliance filing. A request for rehearing of the FERC's May 22, 2006 Order was denied by FERC on October 25, 2006. The estimated annual revenues to ATSI from the VMEP cost recovery is $12 million for each of the five years beginning June 1, 2006.
 
On January 24, 2006, ATSI and MISO filed a request with the FERC to correct ATSI's Attachment 0 formula rate to reverse revenue credits associated with termination of revenue streams from transitional rates stemming from FERC's elimination of RTOR between the Midwest ISO and PJM. Revenues formerly collected under these transitional rates were included in, and served to reduce, ATSI's zonal transmission rate under the Attachment O formula. Absent the requested correction, elimination of these revenue credits would not be fully reflected in ATSI's formula rate until June 1, 2008. On March 16, 2006, the FERC approved the revenue credit correction without suspension, effective April 1, 2006. One party sought rehearing of the FERC's order, which was denied on June 27, 2006. No petition for review of the FERC's decision was filed. The estimated revenue impact of the correction mechanism is approximately $37 million for the period June 1, 2006 though May 31, 2007.

On November 18, 2004, the FERC issued an order eliminating the RTOR for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a SECA mechanism to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES participated in the FERC hearings held in May 2006 concerning the calculation and imposition of the SECA charges. The Presiding Judge issued an Initial Decision on August 10, 2006, rejecting the compliance filings made by the RTOs and transmission owners, ruling on various issues and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the Initial Decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC in early 2007.

On January 31, 2005, certain PJM transmission owners made three filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. American Electric Power Company, Inc. filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to refund and hearing procedures. On June 30, 2005, the settling PJM transmission owners filed a request for rehearing of the May 31, 2005 order. On March 20, 2006, a settlement was filed with FERC in the formula rate proceeding that generally accepts the companies' formula rate proposal. The FERC issued an order approving this settlement on April 19, 2006. Hearings in the PJM rate design case concluded in April 2006. On July 13, 2006, an Initial Decision was issued by the ALJ. The ALJ adopted the FERC Trial Staff's position that the cost of all PJM transmission facilities should be recovered through a postage stamp rate. The ALJ recommended an April 1, 2006 effective date for this change in rate design. If the FERC accepts this recommendation, the transmission rate applicable to many load zones in PJM would increase. FirstEnergy believes that significant additional transmission revenues would have to be recovered from the JCP&L, Met-Ed and Penelec transmission zones within PJM. JCP&L, Met-Ed and Penelec, as part of the Responsible Pricing Alliance, filed a brief addressing the Initial Decision on August 14, 2006 and September 5, 2006. The case will be reviewed by the FERC with a decision anticipated in early 2007. 

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 CBP 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.
 
 
10

 

On December 29, 2005, the FERC issued an order setting the two power sales agreements for hearing. The order criticized the Ohio CBP, and required FES to submit additional evidence in support of the reasonableness of the prices charged in the power sales agreements. On July 14, 2006, the Chief Judge granted the joint motion of FES and the Trial Staff to appoint a settlement judge in this proceeding and the procedural schedule was suspended pending settlement discussions among the parties. A settlement conference was held on September 5, 2006. FES and the Ohio Companies, Penn, and the PUCO, along with other parties, reached an agreement to settle the case. The settlement was filed with the FERC on October 17, 2006, and was unopposed by the remaining parties, including the FERC Trial Staff. This settlement was accepted by the FERC on December 8, 2006.

The terms of the settlement provide for modification of both the Ohio and Penn power supply agreements with FES. Under the Ohio power supply agreement, separate rates are established for the Ohio Companies' PLR requirements; special retail contract requirements, wholesale contract requirements, and interruptible buy-through retail load requirements. For their PLR and special retail contract requirements, the Ohio Companies will pay FES no more than the lower of (i) the sum of the retail generation charge, the rate stabilization charge, the fuel recovery mechanism charge, and FES' actual incremental fuel costs for such sales; or (ii) the wholesale price cap. Different wholesale price caps are imposed for PLR sales, special retail contracts, and wholesale contracts. The wholesale price for interruptible buy-through retail load requirements is limited to the actual spot price of power obtained by FES to provide this power. FES billed the Ohio Companies for the additional amount payable to FES for incremental fuel costs on power supplied during 2006. The total power supply cost billed by FES was lower in each case than the wholesale price caps specified in the settlement accepted by the FERC. In addition, pursuant to the settlement, the wholesale rate charged by FES under the Penn power supply agreement can be no greater than the generation component of charges for retail PLR load in Pennsylvania. The modifications to the Ohio and Pennsylvania power supply agreements became effective January 1, 2006. The Penn supply agreement subject to the settlement expired at midnight on December 31, 2006.

As a result of Penn's PLR competitive solicitation process approved by the PPUC for the period January 1, 2007 through May 31, 2008, FES was selected as the winning bidder for a number of the tranches for individual customer classes. The balance of the tranches will be supplied by unaffiliated power suppliers. On October 2, 2006, FES filed an application with the FERC under Section 205 of the Federal Power Act for authorization to make these affiliate sales to Penn. Interventions or protests were due on this filing on October 23, 2006. Penn was the only party to file an intervention in this proceeding. This filing was accepted by the FERC on November 15, 2006, and no requests for rehearing were filed.
 
           On February 15, 2007, MISO filed documents with the FERC to establish a market-based, competitive ancillary services market. MISO contends that the filing will integrate operating reserves into MISO's existing day-ahead and real-time settlements process, incorporate opportunity costs into these markets, address scarcity pricing through the implementation of a demand curve methodology, foster demand response in the provision of operating reserves, and provide for various efficiencies and optimization with regard to generation dispatch. The filing also proposes amendments to existing documents to provide for the transfer of balancing functions from existing local balancing authorities to MISO. MISO will then carry out this reliability function as the NERC-certified balancing authority for the MISO region. MISO is targeting implementation for the second or third quarter of 2008. The FERC has established March 23, 2007, as the date for interested parties to submit comments addressing the filing. The filing has not yet been fully evaluated to assess its impact on FirstEnergy's operations.
 
           On February 16, 2007, the FERC issued a final rule that revises its decade-old open access transmission regulations and policies. The FERC explained that the final rule is intended to strengthen non-discriminatory access to the transmission grid, facilitate FERC enforcement, and provide for a more open and coordinated transmission planning process. The final rule will not be effective until 60 days after publication in the Federal Register. The final rule has not yet been fully evaluated to assess its impact on FirstEnergy's operations.

Capital Requirements

Capital expenditures for the Companies, FES and FirstEnergy's other subsidiaries for the years 2007 through 2011 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.
 
 
11



   
2006
 
Capital Expenditures Forecast
 
   
Actual
 
2007
 
2008-2011
 
Total
 
 
(In millions) 
OE
 
$
105
 
$
120
 
$
544
 
$
664
 
Penn
   
19
   
26
   
86
   
112
 
CEI
   
127
   
158
   
683
   
841
 
TE
   
61
   
64
   
261
   
325
 
JCP&L
   
160
   
192
   
1,144
   
1,336
 
Met-Ed
   
85
   
83
   
428
   
511
 
Penelec
   
111
   
92
   
522
   
614
 
ATSI
   
39
   
46
   
296
   
342
 
FGCO
   
213
   
445
   
1,712
   
2,157
 
NGC
   
204
   
126
   
534
   
660
 
Other subsidiaries
   
46
   
91
   
239
   
330
 
Total
 
$
1,170
 
$
1,443
 
$
6,449
 
$
7,892
 

During the 2007-2011 period, maturities of, and sinking fund requirements for, long-term debt of FirstEnergy and its subsidiaries are:

   
Long-Term Debt Redemption Schedule
 
   
2007
 
2008-2011
 
Total
 
   
(In millions)
 
                  
OE
 
$
3
 
$
180
 
$
183
 
Penn*
   
1
   
4
   
5
 
CEI**
   
120
   
275
   
395
 
TE
   
30
   
-
   
30
 
JCP&L
   
33
   
119
   
152
 
Met-Ed
   
50
   
100
   
150
 
Penelec
   
-
   
159
   
159
 
FirstEnergy
   
-
   
1,500
   
1,500
 
Other subsidiaries
   
4
   
25
   
29
 
Total
 
$
241
 
$
2,362
 
$
2,603
 
                     
* Penn has an additional $63 million due to associated companies in 2008-2011.
** CEI has an additional $65 million due to associated companies in 2008-2011.
 
           FirstEnergy's investments for additional nuclear fuel during the 2007-2011 period are estimated to be approximately $893 million, of which about $86 million applies to 2007. During the same period, its nuclear fuel investments are expected to be reduced by approximately $702 million and $103 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 2007-2011 period.

 
 
Net Operating Lease Commitments
 
 
 
2007
 
2008-2011
 
Total
 
 
(In millions) 
OE
 
$
86
 
$
428
 
$
514
 
CEI
   
14
   
52
   
66
 
TE
   
79
   
291
   
370
 
JCP&L
   
8
   
32
   
40
 
Met-Ed
   
4
   
16
   
20
 
Penelec
   
5
   
16
   
21
 
FESC
   
8
   
31
   
39
 
Total
 
$
204
 
$
866
 
$
1,070
 
 
                   FirstEnergy had approximately $1.1 billion of short-term indebtedness as of December 31, 2006, comprised of $1.0 billion in borrowings from a $2.75 billion revolving line of credit and $103 million of other bank borrowings. Total short-term bank lines of committed credit to FirstEnergy and the Companies as of December 31, 2006 were approximately $3.4 billion.
 
 
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                   On August 24, 2006, FirstEnergy and certain of its subsidiaries entered into a new $2.75 billion five-year revolving credit facility, which replaced FirstEnergy's prior $2 billion credit facility. FirstEnergy may request an increase in the total commitments available under the new facility up to a maximum of $3.25 billion. Commitments under the new facility are available until August 24, 2011, unless the lenders agree, at the request of the Borrowers, to two additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each Borrower are subject to a specified sublimit, as well as applicable regulatory and other limitations. As of December 31, 2006, FirstEnergy was the only borrower on this revolver with an outstanding balance of $1.0 billion. The annual facility fee is 0.125%.
 
                   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 FirstEnergy's short-term working capital requirements and those of its subsidiaries. Total unused borrowing capability under existing facilities and accounts receivable financing facilities totaled $1.8 billion as of December 31, 2006. An additional source of ongoing cash for FirstEnergy, as a holding company, is cash dividends from its subsidiaries. In 2006, the holding company received $560 million of cash dividends on common stock from its subsidiaries.

Based on their present plans, the Companies could provide for their cash requirements in 2007 from the following sources: funds to be received from operations; available cash and temporary cash investments as of December 31, 2006 (FirstEnergy's non-utility subsidiaries - $90 million and OE - $1 million); the issuance of long-term debt (for refunding purposes); funds from capital markets 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 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, 2006, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.8 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE, CEI and TE 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, CEI and TE to incur additional secured debt not otherwise permitted by a specified exception of up to $543 million, $491 million and $126 million, respectively, as of December 31, 2006. Under the provisions of its senior note indenture, JCP&L may issue additional FMB only as collateral for senior notes. As of December 31, 2006, JCP&L had the capability to issue $678 million of additional senior notes upon the basis of FMB collateral.
 
                   As of December 31, 2006, each of OE, TE, Penn and JCP&L have redeemed all of their outstanding preferred stock. As a result of these redemptions, the applicable earnings coverage tests in each of their respective charters are inoperative. In the event that any of OE, TE, Penn and JCP&L issues preferred stock in the future, the applicable earnings coverage test will govern the amount of preferred stock that may be issued. CEI, Met-Ed and Penelec do not have similar restrictions and could issue up to the number of preferred shares authorized under their respective charters.

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, 2006, approximately $1.0 billion of capacity remained unused under an existing shelf registration statement, filed by FirstEnergy with the SEC in 2003, to support future securities issuances. The shelf registration provides the flexibility to issue and sell various types of securities, including common stock, debt securities, and share purchase contracts and related share purchase units. As of December 31, 2006, OE and CEI had approximately $400 million and $250 million, respectively, of capacity remaining unused under their existing shelf registrations for unsecured debt securities.
 
 
13

 

Nuclear Regulation
 
                   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 DOJ related to FENOC's communications with the NRC during the fall of 2001 in connection with the reactor head issue at the Davis-Besse Nuclear Power Station. Under the agreement, the United States acknowledged FENOC's extensive corrective actions at Davis-Besse, FENOC's cooperation during investigations by the DOJ and the NRC, FENOC's pledge of continued cooperation in any related criminal and administrative investigations and proceedings, FENOC's acknowledgement of responsibility for the behavior of its employees, and its agreement to pay a monetary penalty. The DOJ agreed to 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 remained in compliance with the agreement, which FENOC has done. FENOC paid a monetary penalty of $28 million (not deductible for income tax purposes) which reduced FirstEnergy's earnings by $0.09 per common share in the fourth quarter of 2005. The deferred prosecution agreement expired on December 31, 2006.
 
           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 FirstEnergy 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.
 
           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.
 
           On April 4, 2005, the NRC held a public meeting to discuss FENOC's performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.
 
           On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance at the Perry Nuclear Power Plant and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. In the NRC's 2005 annual assessment letter dated March 2, 2006 and associated meetings to discuss the performance of the Perry Nuclear Power Plant on March 14, 2006, the NRC again stated that the Perry Nuclear Power Plant continued to operate in a manner that "preserved public health and safety." However, the NRC also stated that increased levels of regulatory oversight would continue until sustained improvement in the performance of the facility was realized. 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.

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 million (OE - $5.1 million, NGC - $52.1 million, and TE - $2.8 million) in any one year for each incident.
 
 
14


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 $1.96 billion (OE - $168 million, NGC - $1.703 billion, TE - $89 million) for replacement power costs incurred during an outage after an initial 20-week waiting period. Members of NEIL I pay annual premiums and are subject to assessments if losses exceed the accumulated funds available to the insurer. FirstEnergy's present maximum aggregate assessment for incidents at any covered nuclear facility occurring during a policy year would be approximately $15.1 million (OE - $1.3 million, NGC - $13.2 million, and TE - $0.6 million).
 
           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 $56.8 million (OE - $5.3 million, NGC - $48.5 million, TE - $2.2 million, Met-Ed - $0.4 million, Penelec - $0.2 million and JCP&L - $0.2 million) during a policy year. On September 30, 2003, FirstEnergy tendered a Proof of Loss under the NEIL policies for property damage and accidental outage losses associated with the extended outage at the Davis-Besse Nuclear Power Station, which began in February 2002. In December 2004, NEIL denied FirstEnergy's claim. FirstEnergy requested binding arbitration under the policies and has submitted expert testimony to support its claim. Under NEIL's policies, the arbitrators shall award reasonable attorney's fees and costs to the prevailing party.

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 FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergy with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, FirstEnergy believes it is in compliance with existing regulations but is unable to predict future changes in regulatory policies and what, if any, the effects of such changes would be. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $1.8 billion for 2007 through 2011.
 
                   FirstEnergy accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in FirstEnergy's determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.

Clean Air Act Compliance
 
                   FirstEnergy is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $32,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. FirstEnergy believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
 
 
15

 
 
           The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006 alleging violations to various sections of the Clean Air Act. FirstEnergy has disputed those alleged violations based on its Clean Air Act permit, the Ohio SIP and other information provided at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated.
 
                   FirstEnergy complies with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOX reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOX reductions at FirstEnergy's facilities. The EPA's NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOX emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.

National Ambient Air Quality Standards
 
           In July 1997, the EPA promulgated changes in the NAAQS for ozone and fine particulate matter. In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR provided each affected state until 2006 to develop implementing regulations to achieve additional reductions of 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 caps on SO2 and NOX emissions, whereas its New Jersey fossil-fired generation facility will be subject to only a cap on NOX emissions. According to the EPA, SO2 emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions in affected states to just 2.5 million tons annually. 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. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, mercury emissions will be capped nationally at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and 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 FirstEnergy operates affected facilities.
 
           The model rules for both CAIR and CAMR contemplate an input-based methodology to allocate allowances to affected facilities. Under this approach, allowances would be allocated based on the amount of fuel consumed by the affected sources. FirstEnergy would prefer an output-based generation-neutral methodology in which allowances are allocated based on megawatts of power produced, allowing new and non-emitting generating facilities (including renewables and nuclear) to be entitled to their proportionate share of the allowances. Consequently, FirstEnergy will be disadvantaged if these model rules were implemented as proposed because FirstEnergy's substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.

   Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap and trade approach as in the CAMR, but rather follows a command and control approach imposing emission limits on individual sources. Pennsylvania's mercury regulation would deprive FES of mercury emission allowances that were to be allocated to the Mansfield Plant under the CAMR and that would otherwise be available for achieving FirstEnergy system-wide compliance. The future cost of compliance with these regulations, if approved and implemented, may be substantial.
 
 
16

 

W. H. Sammis Plan
 
          In 1999 and 2000, the EPA issued NOV or compliance orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as the New Source Review cases.
 
                   On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the New Source Review litigation. This settlement agreement, which is in the form of a consent decree, was approved by the Court on July 11, 2005, and requires reductions of 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 we fail 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, we could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation are currently estimated to be $1.5 billion ($400 million of which is expected to be spent in 2007, with the largest portion of the remaining $1.1 billion expected to be spent in 2008 and 2009).

                   The Sammis NSR Litigation consent decree also requires us to spend up to $25 million toward environmentally beneficial projects, $14 million of which is satisfied by entering into 93 MW (or 23 MW if federal tax credits are not applicable) of wind energy purchased power agreements with a 20-year term. An initial 16 MW of the 93 MW consent decree obligation was satisfied during 2006.            
                   On August 26, 2005, FGCO entered into an agreement with Bechtel under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of SO2 emissions. FGCO also entered into an agreement with B&W on August 25, 2006 to supply flue gas desulfurization systems for the reduction of SO2 emissions. Selective Catalytic Reduction (SCR) systems for the reduction of NOx emissions also are being installed at the W.H. Sammis Plant under a 1999 agreement with B&W.
                   OE and Penn agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 included the penalties paid by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized liabilities in the first quarter of 2005 of $9.2 million and $0.8 million, respectively, for probable future cash contributions toward environmentally beneficial projects.

Climate Change
 
                    In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote required for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity - the ratio of emissions to economic output - by 18% through 2012. 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.
 
                   FirstEnergy cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO2 emissions could require significant capital and other expenditures. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.

Clean Water Act
 
                   Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy's plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FirstEnergy's operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.
 
 
17

 
 
                   On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system, and entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. On January 26, 2007, the federal Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to EPA for further rulemaking and eliminated the restoration option from EPA's regulations. FirstEnergy is conducting comprehensive demonstration studies, due in 2008, to determine the operational measures or equipment, if any, necessary for compliance by its facilities with the performance standards. FirstEnergy is unable to predict the outcome of such studies or changes in these requirements from the remand to EPA. Depending on the outcome of such studies and EPA's further rulemaking, the future cost of compliance with these standards may require material capital expenditures.

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

                   Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of December 31, 2006, FirstEnergy had approximately $1.4 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley and Perry. As part of the application to the NRC to transfer the ownership of these nuclear facilities to NGC, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a "real" rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy plans to seek for these facilities.

The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of December 31, 2006, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Total liabilities of approximately $88 million (JCP&L - $59 million, CEI - $2 million, TE - $3 million, and other subsidiaries- $24 million) have been accrued through December 31, 2006.

Fuel Supply

FirstEnergy currently has long-term coal contracts to provide approximately 21.3 million tons of coal for the year 2007. 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, 2028. FirstEnergy estimates its 2007 coal requirements to be approximately 23.2 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.

FirstEnergy is contracted for all uranium requirements through 2009 and a portion of uranium material requirements through 2014. Conversion services contracts fully cover requirements through 2010 and partially fill requirements through 2015. Enrichment services are contracted for all of the enrichment requirements for nuclear fuel through 2011. A portion of enrichment requirements is also contracted for through 2020. Fabrication services for fuel assemblies are contracted for both Beaver Valley units and Davis Besse through 2013 and through the operating license period for Perry (through approximately 2026). The Davis-Besse fabrication contract also has an extension provision for services for three additional consecutive reload batches through the current operating license period (approximately 2017). In addition to the existing commitments, FirstEnergy intends to make additional arrangements for the supply of uranium and for the subsequent conversion, enrichment, fabrication, and waste disposal services.
 
 
18

 

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. FENOC is currently taking actions to extend the storage capacity at both Perry and Beaver Valley Unit 2. 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 on July 19, 2006, the Yucca Mountain Repository is currently projected to start receiving spent fuel in 2017. 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 2017.

System Capacity and Reserves

The 2006 net maximum hourly demand for each of the Companies was: OE-6,024 MW on August 1, 2006; Penn-1,024 MW on August 1, 2006; CEI-4,674 MW on August 1, 2006; TE-2,276 MW on July 31, 2006; JCP&L-6,702 MW on August 2, 2006; Met-Ed-2,996 MW on August 2, 2006; and Penelec-3,069 MW on August 2, 2006. JCP&L's load is supplied through the New Jersey BGS Auction process, transferring substantially all of its load obligation to other parties.
 
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 13,578 MW of owned or leased generation, 463 MW of generation from our 20.5% ownership of OVEC, and approximately 1,360 MW of long-term purchases from Pennsylvania and New Jersey NUGs. FirstEnergy has also entered into approximately 314 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 2006 were 64% and 36% from non-nuclear 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 completed the consolidation of these regions into a single new regional reliability organization known as ReliabilityFirst Corporation. ReliabilityFirst began operations as a regional reliability council under NERC on January 1, 2006 and on November 29, 2006 filed a proposed Delegation Agreement with NERC to obtain certification consistent with the final rule as a "regional entity" under the ERO. All of FirstEnergy's facilities are located within the ReliabilityFirst region.
 
                   The transmission facilities of JCP&L, Met-Ed, and Penelec are controlled by PJM. PJM is the organization responsible for the control of the bulk electric power system throughout major portions of thirteen Mid-Atlantic states and the District of Columbia. PJM is dedicated to meeting the reliability criteria and standards of NERC and the ReliabilityFirst Regional Reliability Organization.

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.
 
 
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As a result of actions taken by state legislative bodies over the last few years, major changes in the electric utility business have occurred 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, Michigan, Maryland and New Jersey.

Competition in Ohio's electric generation market began on January 1, 2001. Pursuant to the generation asset transfers on October 24, 2005 and December 16, 2005, FGCO and NGC own all of the fossil and nuclear generation assets, respectively, previously owned by the Ohio Companies and Penn, and continue to operate those companies' respective leasehold interests. The Ohio Companies continue to obtain their PLR requirements through power supply agreements with FES. JCP&L's obligation to provide BGS has been removed through a transitional mechanism of auctioning the obligation (see "NJBPU Rate Matters"). Met-Ed and Penelec have been purchasing a portion of their PLR requirements from FES through a partial requirements wholesale power sales agreement and various amendments. Under these agreements, FES retained the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec. On January 17, 2007, Met-Ed, Penelec and FES agreed to restate, effective January 1, 2007, their partial requirements wholesale power sales agreement. The restated agreement incorporates the same fixed price for residual capacity and energy supplied by FES as in prior arrangements and allows Met-Ed and Penelec to sell the output of non-utility generation to the market (see "PPUC Rate Matters" for further discussion). As a result of Penn's PLR competitive solicitation process approved by the PPUC for the period January 1, 2007 through May 31, 2008, FES was selected as the winning bidder for a number of the tranches for individual customer classes. The balance of the tranches will be supplied by unaffiliated power suppliers.
 
Research and Development

The Companies participate in funding 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.

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Executive Officers

Name
Age
Position Held During Past Five Years
Dates
       
A. J. Alexander (A)(B)
55
President and Chief Executive Officer
2004-present
   
President and Chief Operating Officer
*-2004
       
L. M. Cavalier
55
Senior Vice President - Human Resources
2005-present
   
Vice President - Human Resources
*-2005
       
M. T. Clark
56
Senior Vice President - Strategic Planning & Operations
2004-present
   
Vice President - Business Development
*-2004
       
K. W. Dindo
57
Vice President and Chief Risk Officer
*-present
       
D. S. Elliott (B)
52
President - Pennsylvania Operations
2005-present
   
Senior Vice President
*-2005
       
R. R. Grigg (A)(B)
58
Executive Vice President and Chief Operating Officer
2004-present
   
President and Chief Executive Officer - WE Generation
Executive Vice President - WEC
2003-2004
*-2003
       
A. Jamshidi
 
 
 
C. E. Jones (A)(B)
52
 
 
 
51
Vice President - Commodity Operations (FES)
Vice President - Energy Delivery
Vice President & Chief Information Officer
 
Senior Vice President - Energy Delivery & Customer Service
Regional Vice President - Operations
2006-present
2004-2006
*-2004
 
2003-present
*-2003
       
C. D. Lasky
44
Vice President - Fossil Operations (FES)
2004-present
   
Plant Director
2003-2004
   
Assistant Plant Director
*-2003
       
G. R. Leidich
56
President and Chief Nuclear Officer - FENOC
2003-present
   
Executive Vice President - FENOC
2002-2003
   
Executive Vice President - Institute of Nuclear Power Ops
*-2002
       
D. C. Luff
59
Senior Vice President - Governmental Affairs
2005-present
   
Vice President
*-2005
       
R. H. Marsh (A)(B)(C)
56
Senior Vice President and Chief Financial Officer
*-present
       
S. E. Morgan (C)
56
President - JCP&L
2004-present
   
Vice President - Energy Delivery
2002-2004
   
Regional President - Central
*-2002
       
J. M. Murray (A)
60
President - Ohio Operations
Regional President - West
2005-present
*-2005
       
J. F. Pearson (A)(B)(C)
52
Vice President and Treasurer
2006-present
   
Treasurer
Group Controller - Strategic Planning and Operations
2005-2006
2004-2005
   
Group Controller - FES
2003-2004
   
Director - FES
*-2003
       
G. L. Pipitone
56
President - FES
2004-present
   
Senior Vice President
*-2004
       
D. R. Schneider
45
Vice President - Energy Delivery
Vice President - Commodity Operations (FES)
2006-present
2004-2006
   
Vice President - Fossil Operations (FES)
*-2004
       
C. B. Snyder
61
Senior Vice President
*-present
       
L.L. Vespoli (A)(B)(C)
47
Senior Vice President and General Counsel
*-present
       
H. L. Wagner (A)(B)(C)
54
Vice President, Controller and Chief Accounting Officer
*-present
       
T. M. Welsh
57
Senior Vice President - External Affairs
2004-present
   
Vice President - Communications
*-2004

(A) Denotes executive officers of OE, CEI and TE.
(B) Denotes executive officers of Met-Ed and Penelec
(C) Denotes executive officers of JCP&L.
* Indicates position held at least since January 1, 2002


21


Employees

As of January 1, 2007, FirstEnergy's nonutility subsidiaries and the Companies had a total of 13,739 employees located in the United States as follows:

FESC
2,991
OE
1,234
CEI
943
TE
420
Penn
198
JCP&L
1,448
Met-Ed
701
Penelec
888
ATSI
36
FES
2,082
FENOC
2,798
Total
13,739

Of the above employees 6,599 (including 253 for FESC; 739 for OE; 645 for CEI; 316 for TE; 149 for Penn; 1,137 for JCP&L; 520 for Met-Ed; 619 for Penelec; 1,252 for FES; and 969 for FENOC) 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 arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. JCP&L intends to re-file an appeal again in federal district court once the damages associated with this case are identified at an individual employee level. JCP&L recognized a liability for the potential $16 million award in 2005.

FirstEnergy Web Site

Each of the registrant's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are also made available free of charge on or through FirstEnergy's internet web site at www.firstenergycorp.com. These reports are posted on the web site as soon as reasonably practicable after they are electronically filed with the SEC.

ITEM 1A. RISK FACTORS
 
                   We operate in a business environment that involves significant risks, many of which are beyond our control. Below, we have identified risks we currently consider material. However, our business, financial condition, cash flows or results of operations could be affected materially and adversely by additional risks not currently known to us or that we deem immaterial at this time. Additional information on risk factors is included in "Item 1. Business" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and in other sections that include forward-looking and other statements involving risks and uncertainties that could impact our business and financial results.

Risks Related to Business Operations

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

Operation of generation, transmission and distribution facilities involves risk, including potential breakdown or failure of equipment or processes, accidents, labor disputes 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.

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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 arrangements for generating facilities upon the occurrence of certain contingent events that could render those facilities worthless. Although we believe these types of events are unlikely to occur, OE, CEI and TE each have a maximum exposure to loss under those 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 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.

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;
   
·
liquidity 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 sabatage, terrorist acts, embargeos and other catastrophic events.
 
 We Are Exposed to Operational, Price and Credit Risks Associated With Selling and Marketing Products in the Power Markets That We Do Not Always Completely Hedge Against

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

 
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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.

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

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.

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 certain unplanned radiological releases associated with the operation of our nuclear facilities and the storage, handling and disposal of radioactive materials;

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

·
uncertainties with respect to contingencies and assessments if insurance coverage is inadequate
and
 
·
uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed operation.

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 $2.0 billion of insurance coverage for replacement power costs. Under these policies, we can be assessed a maximum of approximately $72 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.

24




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 in the United States) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $300.0 million; and (ii) $10.5 billion provided by an industry retrospective rating plan. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $100.6 million (but not more than $15.0 million per year) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Based on our present nuclear ownership, the maximum potential assessment under these provisions would be $402.4 million per incident but not more than $60.0 million in any one year.

We Rely on Transmission and Distribution Assets that we do not Own or Control to Deliver Our Wholesale Electricity. If Transmission is Disrupted Including Our Own Transmission, or not Operated Efficiently, or if Capacity is Inadequate, Our Ability to Sell and Deliver Power may be Hindered.

We depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity we sell. If transmission is disrupted (as a result of weather, natural disasters or other reasons) or not operated efficiently by ISOs, in applicable markets, or if capacity is inadequate, our ability to sell and deliver products and satisfy our contractual obligations may be hindered, or we may be unable to sell products on the most favorable terms.
 
Demand for electricity within our service areas could stress available transmission capacity requiring alternative routing or curtailing of electricity usage with consequent effects on operating costs, revenues and results of operations. In addition, as with all utilities, potential concerns over transmission capacity could result in MISO, PJM or the FERC requiring us to upgrade or expand our transmission system through additional capital expenditures.

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

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

We purchase fuel from a number of suppliers. The lack of availability of fuel, or a disruption in the delivery of fuel, including disruptions as a result of weather, increased transportation costs or other difficulties, labor relations or environmental or other regulations affecting our fuel suppliers, could adversely affect our ability to operate our facilities, which could result in lower sales and/or higher costs and thereby adversely affect our results of operations.

Seasonal Temperature Variations, as well as Weather Conditions or other Natural Disasters Could Have a Negative Impact on Our Results of Operations Specifically with Respect to Our PLR Contracts that do not Provide for a Specific Level of Supply, and Demand Significantly Below or Above our Forecasts Could Adversely Affect our Energy Margins

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, ice or snow storms or droughts or other natural disasters, may cause outages and property damage that may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned under these conditions would be particularly burdensome during a peak demand period.

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

25



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 Goodwill of One or More of Our Operating Subsidiaries May Become Impaired, Which Would Result in Write-Offs of the Impaired Amounts
 
 
There is a possibility that additional goodwill may be impaired at one or more of our operating subsidiaries. The actual timing and amounts of any goodwill impairments in future years would depend on many uncertain variables, including changing interest rates, utility sector market performance, our capital structure, market prices for power, results of future rate proceedings, operating and capital expenditure requirements and other factors.

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 older. 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.

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

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

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 or terrorism 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.

Risks Associated With Regulation

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

26



Regulatory Changes in the Electric Industry Including a Reversal, Discontinuance or Delay of the Present Trend Towards Competitive Markets 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 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.

Some deregulated electricity markets have experienced difficulty in transition to market. In some of these markets, both state and federal government agencies and other interested parties have made proposals to delay market restructuring or even re-regulate areas of these markets that have previously been deregulated. For example, in 2001, the FERC instituted a series of price controls designed to mitigate (or cap) prices in the entire western U.S. to address the extreme volatility in the California electricity markets. These price controls have had the effect of significantly reducing spot and forward electricity prices in the western market. In addition, the ISOs that oversee the transmission systems in certain wholesale electricity markets have from time to time been authorized to impose price limitations and other mechanisms to address volatility in the power markets. Similar types of price limitations and other mechanisms could reduce the profits that our wholesale power marketing business would have realized based on competitive market conditions absent such limitations and mechanisms. Although we expect the deregulated electricity markets to continue to be competitive, other proposals to re-regulate our industry may be made, and legislative or other action affecting the electric power restructuring process may cause the process to be delayed, discontinued or reversed in the states in which we currently, or may in the future, operate. Such delays, discontinuations or reversals of electricity market restructurings in the markets in which we operate could have an impact on our results of operations and financial condition. At a minimum, these types of actions raise uncertainty concerning the continued development of competitive power 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.

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

In 2005 the FERC granted FES, FGCO and NGC authority to sell electricity at market-based rates. The FERC's orders that grant this market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that these companies can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions. As a condition to the orders granting these generating companies market-based rate authority, every three years they are required to file a market power update to show that they continue to meet the FERC's standards with respect to generation market power and other criteria used to evaluate whether entities qualify for market-based rates. They will be required to renew this authority in 2008. If any of these companies were to lose its market-based rate authority or fail to have such authority renewed, it would be required to obtain the FERC's acceptance to sell power at cost-based rates. That company then would become subject to the accounting, record-keeping and reporting requirements that are imposed on utilities with cost-based rate schedules.
 
The FERC has issued a proposed rulemaking to revise the standards used to determine whether an applicant qualifies for market-based authority. In addition, the FERC is considering modifications to other aspects of its market-based rate authorizations, including whether to continue granting waivers of FERC's accounting, record-keeping and reporting requirements that are imposed on utilities with cost-based rates, whether to continue granting blanket approval for future securities issuances or assumptions of liabilities to entities with market-based rate authority, whether to adopt a uniform tariff that applies to all market-based rate sellers, and whether to modify the approach to the three-year market power update filing. The FERC has solicited comments from interested parties on these and other issues. The outcome of this proposed rulemaking proceeding could affect the regulatory requirements applicable to FES, FGCO, and NGC as market-based rate sellers.
 
The Amount We Charge Third Parties for Using Our Transmission Facilities May be Reduced and not Recovered. 

In July 2003, the FERC issued an order directing PJM and the MISO to make compliance filings to eliminate the transaction-based charges for RTOR transmission service on transactions where the energy is delivered within the proposed MISO and PJM expanded regions (Combined Footprint). The elimination of the T&O rates reduces the transmission service revenues collected by the RTOs and thereby reduces the revenues received by transmission owners under the RTOs' revenue distribution protocols. To mitigate the impact of lost RTOR revenues, the FERC approved SECA transition rates beginning in December 2004 and extending through March 2006.

27


A hearing in the SECA case was held in May 2006 to determine whether any of the SECA revenues should be refunded. In August 2006, the ALJ issued an initial decision, finding that the rate design for the recovery of SECA charges was flawed and that a large portion of the "lost revenues" reflected in the SECA rates were not recoverable. The ALJ found that the SECA rates charged were unfair, unjust and discriminatory, and that new compliance filings and refunds should be made. The ALJ also found that unpaid SECA rates must be paid in the recommended reduced amount.

Although we believe we have meritorious arguments, management cannot predict the ultimate outcome of any future FERC proceedings or court appeals. If the FERC adopts the ALJ's decision, it could have an impact on our future results of operations and cash flows. Also, management is unable to predict whether the FERC will approve either the ALJ's decision or when, or if, the effect of the loss of RTOR/SECA transmission revenues will be recoverable in the state retail jurisdictions and/or from transmission users within the PJM region. Therefore, the final amount of our SECA obligations, if any, remains uncertain.

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, we cannot fully assess the impact that these power markets or other ongoing RTO developments may have.

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. In addition, any alleged violation of environmental laws and regulations may require us to expend significant resources to defend against any such alleged violations.
 
               Also, we are generally responsible for on-site liabilities, and in some cases off-site liabilities, associated with the environmental condition of our facilities which we have acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with some acquisitions and sales of assets, we may obtain, or be required to provide, indemnification against some environmental liabilities. If we incur a material liability, or the other party to a transaction fails to meet its indemnification obligations to us, we could suffer material losses.
 
                   The EPA's final CAIR, CAMR and CAVR require significant reductions beginning in 2009 in air emissions from coal-fired power plants and the states have been given substantial discretion in developing their own rules to implement these programs. 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 under these air emission reduction programs may not be known for several years and may differ significantly from the current rules. If the final rules are remanded by the Court of Appeals, 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, 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.
 

28


 
There also is growing concern nationally and internationally about global warming. Further, many states and environmental groups have also challenged certain of the federal laws and regulations relating to air emissions as not being sufficiently strict. As a result, it is possible that state and federal regulations will be developed that will impose more stringent limitations on emissions than are currently in effect. Any such additional limitations on emissions may require us to make increased expenditures for pollution control devices which could have an adverse impact on our results of operations, cash flows and financial condition.
 
                   Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy's plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FirstEnergy's operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.

We are and may Become Subject to Legal Claims Arising from the Presence of Asbestos or Other Regulated Substances at Some of our Facilities
 
                   We have been named as a defendant in pending asbestos litigation involving multiple plaintiffs and multiple defendants. In addition, asbestos and other regulated substances are, and may continue to be, present at our facilities where suitable alternative materials are not available. We believe that any remaining asbestos at our facilities is contained. The continued presence of asbestos and other regulated substances at these facilities, however, could result in additional actions being brought against us.

The Continuing Availability and Operation of Generating Units is Dependent on Retaining the Necessary Licenses, Permits, and Operating Authority from Governmental Entities, Including the NRC
 
We are required to have numerous permits, approvals and certificates from the agencies that regulate our business. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on operating results from future regulatory activities of any of these agencies and we are not assured that any such permits, approvals or certifications will be renewed.

We May Ultimately Incur Liability in Connection with Federal Proceedings

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.

Risks Associated With Financing and Capital Structure

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 to the extent we seek 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.

29



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 is positive. Fitch's ratings outlook is positive for CEI and TE and stable for all other subsidiaries and FirstEnergy.

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

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

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

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

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 first mortgage indentures. See the "Leases" and "Capitalization" notes to the respective financial statements for information concerning leases and financing encumbrances affecting certain of the Companies' properties.

FirstEnergy has access, either through ownership or lease, to the following generation sources as of February 27, 2007, 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.
 
 
30


     
Net
     
Demonstrated
     
Capacity
 
Unit
 
(MW)
Plant-Location
     
Coal-Fired Units
     
Ashtabula-
     
Ashtabula, OH
5
 
                         244
Bay Shore-
     
Toledo, OH
1-4
 
                          631
R. E. Burger-
     
Shadyside, OH
3-5
 
                         406
Eastlake-Eastlake, OH
1-5
 
                      1,233
Lakeshore-
     
Cleveland, OH
18
 
                         245
Bruce Mansfield-
1
 
830(a)
Shippingport, PA
2
 
830(b)
 
3
 
800(c)
       
W. H. Sammis-
1-6
 
                      1,620
Stratton, OH
7
 
                         600
Kyger Creek - Chesire, OH
1-5
 
210(d)
Clifty Creek - Madison, IN
1-6
 
253(d)
Total
   
                      7,902
       
Nuclear Units
     
Beaver Valley-
1
 
                          868
Shippingport, PA
2
 
854(e)
Davis-Besse-
     
Oak Harbor, OH
1
 
                          898
Perry-
     
N. Perry Village, OH
1
 
                          1,258(f)
Total
   
                      3,878
       
Oil/Gas-Fired/
     
Pumped Storage Units
     
Richland-Defiance, OH
1-3
 
                             42
 
4-6
 
                          390
Seneca-Warren, PA
1-3
 
                          443
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(g)
Other
   
                          301
Total
   
                     2,261
Total
   
                    14,041


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% (237 MW) and
17.30% (144 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 )
Represents FGCO's 20.5% entitlement based on FirstEnergy's participation in OVEC.
 
  (e)
Includes OE's and TE's leasehold interests in Beaver Valley Unit 2 of 21.66% (185 MW) and
18.26% (156 MW), respectively.
 
  (f)
Includes OE's leasehold interest in Perry of 12.58% (158 MW).
 
  (g)
Represents JCP&L's 50% ownership interest.

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 15,009 pole miles.

The Companies' electric distribution systems include 116,469 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 90,948,000 kilovolt-amperes.

31


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, 2006, consist of the following:

         
Substation
 
Distribution
 
Transmission
 
Transformer
 
Lines
 
Lines
 
Capacity
 
(Miles)
 
(kV-amperes)
           
OE
30,008
 
550
 
8,298,000
Penn
5,756
 
44
 
1,739,000
CEI
25,130
 
2,144
 
9,301,000
TE
1,851
 
223
 
3,677,000
JCP&L
18,966
 
2,135
 
20,964,000
Met-Ed
14,751
 
1,407
 
9,848,000
Penelec
20,007
 
2,690
 
14,190,000
ATSI*
-
 
5,816
 
22,931,000
Total
116,469
 
15,009
 
90,948,000

 
*
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, JCP&L, Met-Ed and Penelec.

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

    None.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The information required by Item 5 regarding FirstEnergy's market information, including stock exchange listings and quarterly stock market prices, dividends and holders of common stock is included on page 3 of FirstEnergy's 2006 Annual Report to Stockholders (Exhibit 13). Information for OE, CEI, TE, JCP&L, Met-Ed and Penelec is not required to be disclosed because they are wholly owned subsidiaries.

Information regarding compensation plans for which shares of FirstEnergy common stock may be issued is incorporated herein by reference to FirstEnergy's 2007 proxy statement filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.

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 2006.

 
Period
 
October 1-31,
2006
 
November 1-30,
2006
 
December 1-31,
2006
 
Fourth Quarter
Total Number Of Shares Purchased (a)
234,384
 
76,844
 
331,411
 
642,639
Average Price Paid per Share
$58.02
 
$58.90
 
$60.58
 
$59.45
Total Number of Shares Purchased As Part of Publicly  Announced Plans Or Programs
-
 
-
 
-
 
-
Maximum Number (or Approximate Dollar Value) of Shares that  May Yet Be Purchased Under the Plans Or Programs (b)
1,369,241
 
1,369,241
 
1,369,241
 
1,369,241

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

(b)
FirstEnergy initiated a share repurchase plan on August 10, 2006.

32


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 2006 Annual Report to Stockholders (Exhibit 13).

 
Item 6
Item 7
Item 7A
Item 8
         
FirstEnergy
3
5-51
29-32
52-105
OE
2
3-20
11-12
21-49
CEI
2
3-19
11
20-46
TE
2
3-19
11
20-45
JCP&L
2
3-15
7-9
16-40
Met-Ed
2
3-14
7-9
15-37
Penelec
2
3-14
7-9
15-37

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, 2006.

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, 2006. Management's assessment of the effectiveness of FirstEnergy's internal control over financial reporting, as of December 31, 2006, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report included in FirstEnergy's 2006 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 2006 that have materially affected, or are reasonably likely to materially affect, FirstEnergy's internal control over financial reporting.

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

Evaluation of Disclosure Controls and Procedures
 
           Each registrant's Chief Executive Officer and Chief Financial Officer have reviewed and evaluated such registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934 rules 13a-15(e) and 15d-15(e), as of the end date covered by this report. Based upon this evaluation, the respective Chief Executive Officer and Chief Financial Officer concluded that such registrant's disclosure controls and procedures were effective as of December 31, 2006.

33


Changes in Internal Control over Financial Reporting
 
           There were no changes in the registrants' internal control over financial reporting during the fourth quarter of 2006 that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting.


ITEM 9B. OTHER INFORMATION
 
           None.

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 2007 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, 2006.

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

A. J. Alexander, R. H. Marsh and R. R. Grigg are the Directors of OE, 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 46) has served as FirstEnergy Service Company's Vice President - Energy Delivery since 2004. From 1999 to 2004, Mr. Ewing served as Director of Operations Services - Northern Region.

Mr. Julian (Age 50) 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.

Mrs. Persson (Age 76) 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.

Mr. Van Ness (Age 73) 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.

34




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, JCP&L, Met-Ed and Penelec -

The information required by Items 11, 12 and 13 is incorporated herein by reference to FirstEnergy's 2007 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, 2006 and 2005 are as follows:

   
Audit Fees(1)
 
Audit-Related Fees
 
Company
 
2006
 
2005
 
2006
 
2005
 
   
(In thousands)
 
OE
 
$
1,495
 
$
1,492
 
$
-
 
$
-
 
CEI
   
726
   
755
   
-
   
-
 
TE
   
643
   
610
   
-
   
-
 
JCP&L
   
816
   
728
   
-
   
-
 
Met-Ed
   
576
   
597
   
-
   
-
 
Penelec
   
576
   
605
   
-
   
-
 
Other subsidiaries
   
1,478
   
1,786
   
-
   
-
 
                           
Total FirstEnergy
 
$
6,310
 
$
6,573
 
$
-
 
$
-
 

 
 
(1)
Professional services rendered for the audits of FirstEnergy's annual financial statements and reviews of financial statements included in FirstEnergy's Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.
 
 
Tax and Other Fees
 
There were no other fees billed to FirstEnergy for tax or other services for the years ended December 31, 2006 and 2005.

Additional information required by this item is incorporated herein by reference to FirstEnergy's 2007 Proxy Statement filed with the SEC pursuant to Regulation 14A.


35


PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) 1. Financial Statements

Included in Part II of this report and incorporated herein by reference to the respective company's 2006 Annual Report to Stockholders (Exhibit 13 below) at the pages indicated.

 
First-
Energy
 
OE
 
CEI
 
TE
 
JCP&L
 
Met-Ed
 
Penelec
 
               
Management Reports
1
-
-
-
-
-
-
Report of Independent Registered Public Accounting Firm
2
1
1
1
1
1
1
Statements of Income-Three Years Ended December 31, 2006
52
21
20
20
16
15
15
Balance Sheets-December 31, 2006 and 2005
53
22
21
21
17
16
16
Statements of Capitalization-December 31, 2006 and 2005
54-55
23-24
22
22
18
17
17
Statements of Common Stockholders' Equity-Three Years
Ended December 31, 2006
56
25
23
23
19
18
18
Statements of Preferred Stock-Three Years Ended
December 31, 2006
57
25
23
23
19
-
-
Statements of Cash Flows-Three Years Ended December 31, 2006
58
26
24
24
20
19
19
Statements of Taxes-Three Years Ended December 31, 2006
 
27
25
25
21
20
20
Notes to Financial Statements
59-105
28-49
26-46
26-45
22-40
21-37
21-37

2.  
Financial Statement Schedules

    Included in Part IV of this report:

 
First-
Energy
 
OE
 
CEI
 
TE
 
JCP&L
 
Met-Ed
 
Penelec
 
               
Report of Independent Registered Public Accounting
Firm
71
72
73
74
75
76
77
               
Schedule - Three Years Ended December 31, 2006:
II - Consolidated Valuation and Qualifying Accounts
78
79
80
81
82
83
84

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

3.  
Exhibits - FirstEnergy

Exhibit
Number

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)

 
36


Exhibit
Number
 
   
(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)
   
(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 10-1)
   
(C)10-10
Restricted Stock Agreement between FirstEnergy Corp. and H. P. Burg. (2000 Form 10-K, Exhibit 10-2)
   
(C)10-11
Stock Option Agreement between FirstEnergy Corp. and officers dated November 22, 2000. (2000 Form 10-K, Exhibit 10-3)
   
(C)10-12
Stock Option Agreement between FirstEnergy Corp. and officers dated March 1, 2000. (2000 Form 10-K, Exhibit 10-4)
   
(C)10-13
Stock Option Agreement between FirstEnergy Corp. and director dated January 1, 2000. (2000 Form 10-K, Exhibit 10-5)
   
(C)10-14
Stock Option Agreement between FirstEnergy Corp. and two directors dated January 1, 2001. (2000 Form 10-K, Exhibit 10-6)
   
(C)10-15
Executive and Director Incentive Compensation Plan dated May 15, 2001. (2001 Form 10-K, Exhibit 10-1)
   
(C)10-16
Amended FirstEnergy Corp. Deferred Compensation Plan for Directors, revised September 18, 2000. (2001 Form 10-K, Exhibit 10-2)
   
(C)10-17
Stock Option Agreements between FirstEnergy Corp. and Officers dated May 16, 2001. (2001 Form 10-K, Exhibit 10-3)
   
(C)10-18
Form of Restricted Stock Agreements between FirstEnergy Corp. and Officers. (2001 Form 10-K, Exhibit 10-4)
   
(C)10-19
Stock Option Agreements between FirstEnergy Corp. and One Director dated January 1, 2002. (2001 Form 10-K, Exhibit 10-5)
   
(C)10-20
FirstEnergy Corp. Executive Deferred Compensation Plan. (2001 Form 10-K, Exhibit 10-6)
   
(C)10-21
Executive Incentive Compensation Plan-Tier 2. (2001 Form 10-K, Exhibit 10-7)
   
(C)10-22
Executive Incentive Compensation Plan-Tier 3. (2001 Form 10-K, Exhibit 10-8)
   
(C)10-23
Executive Incentive Compensation Plan-Tier 4. (2001 Form 10-K, Exhibit 10-9)
   
(C)10-24
Executive Incentive Compensation Plan-Tier 5. (2001 Form 10-K, Exhibit 10-10)
   
(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 10-11)
   
(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 10-12)
   
(C)10-27
GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group, Inc. Employees. (2001 Form 10-K, Exhibit 10-13)
 
 
37

 
Exhibit
Number
   
(C)10-28
Executive and Director Stock Option Agreement dated June 11, 2002. (2002 Form 10-K, Exhibit 10-1)
   
(C)10-29
Director Stock Option Agreement. (2002 Form 10-K, Exhibit 10-2)
   
(C)10-30
Executive and Director Executive Incentive Compensation Plan, Amendment dated May 21, 2002. (2002 Form 10-K, Exhibit 10-3)
   
(C)10-31
Directors Deferred Compensation Plan, Revised Nov. 19, 2002. (2002 Form 10-K, Exhibit 10-4)
   
(C)10-32
Executive Incentive Compensation Plan 2002. (2002 Form 10-K, Exhibit 10-5)
   
(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 10-12)
   
(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 10-13)
   
(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 10-14)
   
(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 10-15)
 
 
38

 
Exhibit
Number
 
 
(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 10-16)
   
(C)10-50
Executive and Director Incentive Compensation Plan, Amendment dated January 18, 2005. (2004 Form 10-K, Exhibit 10-3)
   
(C)10-51
Form of Restricted Stock Agreements, between FirstEnergy and Officers. (2004 Form 10-K, Exhibit 10-4)
   
(C)10-52
Form of Restricted Stock Unit Agreements (Performance Adjusted), between FirstEnergy and Officers. (2004 Form 10-K, Exhibit 10-5)
   
(C)10-53
Form of Restricted Stock Agreement, between FirstEnergy and an officer. (2004 Form 10-K, Exhibit 10-6)
   
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)
   
    (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. (2005 Form 10-K, Exhibit 10-1)
   
    (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. (2005 Form 10-K, Exhibit 10-3)
   
10-60
GENCO Power Supply Agreement dated as of October 14, 2005 between FirstEnergy Generation Corp. (Seller) and FirstEnergy Solutions Corp. (Buyer). (2005 Form 10-K, Exhibit 10-5)
   
10-61
Nuclear Power Supply Agreement dated as of October 14, 2005 between FirstEnergy Nuclear Generation Corp. (Seller) and FirstEnergy Solutions Corp. (Buyer). (2005 Form 10-K, Exhibit 10-8)
   
    (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. (2005 Form 10-K, Exhibit 10-2)
   
    (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. (2005 Form 10-K, Exhibit 10-4)
   
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) (2005 Form 10-K, Exhibit 10-6)
   
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) (2005 Form 10-K, Exhibit 10-7)
   
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) (2005 Form 10-K, Exhibit 10-9)
   
10-67
Electric Power Supply Agreement dated as of October 31, 2005 between FirstEnergy Solutions Corp. (Seller) and Pennsylvania Power Company (Buyer). (2005 Form 10-K, Exhibit 10-10)
   
 

 
39

 
Exhibit
Number
(E)10-68
Form of Guaranty Agreement dated as of April 3, 2006 by FirstEnergy Corp. in favor of the Participating Banks, Barclays Bank PLC, as administrative agent and fronting bank, and KeyBank National Association, as syndication agent, under the related Letter of Credit and Reimbursement Agreement. (March 2006 10-Q, Exhibit 10-1)
   
(E)10-69
Form of Letter of Credit and Reimbursement Agreement dated as of April 3, 2006 among FirstEnergy Generation Corp., the Participating Banks, Barclays Bank PLC, as administrative agent and fronting bank, and KeyBank National Association, as syndication agent. (March 2006 10-Q, Exhibit 10-2)
   
(E)10-70
Form of Trust Indenture dated as of April 1, 2006 between the Ohio Water Development Authority and The Bank of New York Trust Company, N.A. as Trustee securing pollution control revenue refunding bonds issued on behalf of FirstEnergy Generation Corp. (March 2006 10-Q, Exhibit 10-3)
   
(E)10-71
Form of Waste Water Facilities Loan Agreement between the Ohio Water Development Authority and FirstEnergy Generation Corp. dated as of April 1, 2006. (March 2006 10-Q, Exhibit 10-4)
   
(C)10-72
Form of Restricted Stock Agreement between FirstEnergy and A. J. Alexander, dated February 27, 2006. (March 2006 10-Q, Exhibit 10-6)
   
(C)10-73
Form of Restricted Stock Unit Agreement (Performance Adjusted) between FirstEnergy and A.J. Alexander, dated March 1, 2006. (March 2006 10-Q, Exhibit 10-7)
   
(C)10-74
Form of Restricted Stock Unit Agreement (Performance Adjusted) between FirstEnergy and named executive officers, dated March 1, 2006. (March 2006 10-Q, Exhibit 10-8)
   
(C)10-75
Form of Restricted Stock Unit Agreement (Discretionary) between FirstEnergy and R.H. Marsh, dated March 1, 2006. (March 2006 10-Q, Exhibit 10-9)
   
10-76
Confirmation dated August 9, 2006 between FirstEnergy Corp and JP Morgan Chase Bank National Association (September 2006 10-Q, Exhibit 10-1)
   
     (A)(F)10-77
Form of Trust Indenture dated as of December 1, 2006 between the Ohio Water Development Authority and The Bank of New York Trust Company, N.A. as Trustee securing State of Ohio Pollution Control Revenue Refunding Bonds (FirstEnergy Nuclear Generation Corp. Project) (Form 8-K dated December 5, 2006)
   
(A)(G)10-78
Form of Supplemental Letter of Credit Agreement, dated as of December 5, 2006 among FirstEnergy Corp., FirstEnergy Generation Corp. and Barclays Bank PLC, as Fronting Bank (FirstEnergy Generation Corp. Project) (Form 8-K dated December 5, 2006)
   
(A)10-79
Form of Letter of Credit and Reimbursement Agreement dated as of December 28, 2006 among FirstEnergy Corp., as Obligor, The Lenders Named Herein, as Lender, and Wachovia Fixed Income Structured Trading Solutions, LLC as Administrative Agent and as Fronting Bank (Form 8-K dated December 5, 2006)
   
      (A)(F)10-80
Form of Waste Water Facilities and Solid Waste Facilities Loan Agreement between the Ohio Water Development Authority and FirstEnergy Nuclear Generation Corp. dated as of December 1, 2006. (Form 8-K dated December 5, 2006)
   
       (A)(C)10-81
Amendment to Employment Agreement for Richard R. Grigg dated January 16, 2007. (Form 8-K dated January 16, 2007)
   
 

 
40


Exhibit
Number
 
(A)12.1
Consolidated fixed charge ratios.
   
(A)13
FirstEnergy 2006 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, 2006.
   
(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).
   
(A)31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
   
(A)32
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
   
(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.
   
(E)
Three substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to three other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority and the Beaver County Industrial Development Authority relating to pollution control notes of FirstEnergy Generation Corp. and FirstEnergy Nuclear Generation Corp.
   
(F)
Seven substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to one other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority, three other series of pollution control bonds issued by the Ohio Air Quality Development Authority and the three other series of pollution control bonds issued by the Beaver County Industrial Development Authority, relating to pollution control notes of FirstEnergy Generation Corp. and FirstEnergy Nuclear Generation Corp.
   
(G)
Two substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to two other series of pollution control revenue refunding bonds issued by the Ohio Air Quality Development Authority, and the Beaver County Industrial Development Authority relating to pollution control notes of FirstEnergy Generation Corp.

(B) 3. Exhibits - 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:


41


Exhibit
Number
 
   
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, 1945
2-61146
2(b)(2)
September 1, 1948
2-61146
2(b)(2)
May 1, 1950
2-61146
2(b)(2)
January 1, 1954
2-61146
2(b)(2)
May 1, 1955
2-61146
2(b)(2)
August 1, 1956
2-61146
2(b)(2)
March 1, 1958
2-61146
2(b)(2)
April 1, 1959
2-61146
2(b)(2)
June 1, 1961
2-61146
2(b)(2)
September 1, 1969
2-34351
2(b)(2)
May 1, 1970
2-37146
2(b)(2)
September 1, 1970
2-38172
2(b)(2)
June 1, 1971
2-40379
2(b)(2)
August 1, 1972
2-44803
2(b)(2)
September 1, 1973
2-48867
2(b)(2)
May 15, 1978
2-66957
2(b)(4)
February 1, 1980
2-66957
2(b)(5)
   
Incorporated by
   
Reference to
Dated as of
File Reference
Exhibit No.
April 15, 1980
2-66957
2(b)(6)
June 15, 1980
2-68023
(b)(4)(b)(5)
October 1, 1981
2-74059
(4)(d)
October 15, 1981
2-75917
(4)(e)
February 15, 1982
2-75917
(4)(e)
July 1, 1982
2-89360
(4)(d)
March 1, 1983
2-89360
(4)(e)
March 1, 1984
2-89360
(4)(f)
September 15, 1984
2-92918
(4)(d)
September 27, 1984
33-2576
(4)(d)
November 8, 1984
33-2576
(4)(d)
December 1, 1984
33-2576
(4)(d)
December 5, 1984
33-2576
(4)(e)
January 30, 1985
33-2576
(4)(e)
February 25, 1985
33-2576
(4)(e)
July 1, 1985
33-2576
(4)(e)
October 1, 1985
33-2576
(4)(e)
January 15, 1986
33-8791
(4)(d)
May 20, 1986
33-8791
(4)(d)
June 3, 1986
33-8791
(4)(e)
October 1, 1986
33-29827
(4)(d)
August 25, 1989
33-34663
(4)(d)
February 15, 1991
33-39713
(4)(d)
May 1, 1991
33-45751
(4)(d)
May 15, 1991
33-45751
(4)(d)
September 15, 1991
33-45751
(4)(d)
April 1, 1992
33-48931
(4)(d)
June 15, 1992
33-48931
(4)(d)
September 15, 1992
33-48931
(4)(e)
April 1, 1993
33-51139
(4)(d)

 
 
42

 
Exhibit
Number
 

June 15, 1993
33-51139
(4)(d)
September 15, 1993
33-51139
(4)(d)
November 15, 1993
1-2578
(4)(2)
April 1, 1995
1-2578
(4)(2)
May 1, 1995
1-2578
(4)(2)
July 1, 1995
1-2578
(4)(2)
June 1, 1997
1-2578
(4)(2)
April 1, 1998
1-2578
(4)(2)
June 1, 1998
1-2578
(4)(2)
September 29, 1999
1-2578
(4)(2)
April 1, 2000
1-2578
(4)(2)(a)
April 1, 2000
1-2578
(4)(2)(b)
June 1, 2001
1-2578
 
February 1, 2003
1-2578
4(2)
March 1, 2003
1-2578
4(2)
August 1, 2003
1-2578
4(2)
June 1, 2004
1-2578
4(2)
June 1, 2004
1-2578
4(2)
December 1, 2004
1-2578
4(2)
April 1, 2005
1-2578
4(2)
April 15, 2005
1-2578
4(2)
June 1, 2005
1-2578
4(2)
     
(B) 4-2
General Mortgage Indenture and Deed of Trust dated as of January 1, 1998 between OE and the Bank of New York, as Trustee, as amended and supplemented by Supplemental Indentures; (Registration No. 333-05277, Exhibit 4(g)).

February 1, 2003
1-2578
4-2
March 1, 2003
1-2578
4-2
August 1, 2003
1-2578
4-2
June 1, 2004
1-2578
4-2
June 1, 2004
1-2578
4-2
December 1, 2004
1-2578
4-2
April 1, 2005
1-2578
4(2)
April 15, 2005
1-2578
4(2)
June 1, 2005
1-2578
4(2)

4-3
Indenture dated as of April 1, 2003 between OE and The Bank of New York, as Trustee.
   
4-4
Officer's Certificate (including the forms of the 6.40% Senior Notes due 2016 and the 6.875% Senior Notes due 2036), dated June 21, 2006. (Form 8-K dated June 26, 2006, Exhibit 4)
   
10-1
Administration Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-43102, Exhibit 5(c)(2))
   
10-2
Amendment No. 1 dated January 4, 1974 to Administration Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-68906, Exhibit 5(c)(3))
   
10-3
Transmission Facilities Agreement between the CAPCO Group dated as of September 14, 1967. (Registration No. 2-43102, Exhibit 5(c)(3))
   
10-4