main10_q.htm


 
 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C.  20549

FORM 10-Q
(Mark One)
[X]  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2008

OR

[  ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the transition period from
 
to
 

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

 
 

 

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

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

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

Large Accelerated Filer
(X)
 
FirstEnergy Corp.
Accelerated Filer
(  )
 
N/A
Non-accelerated Filer (Do not check if a smaller reporting company)
(X)
FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company

Smaller Reporting Company
(  )
N/A

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

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

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

 
    OUTSTANDING
CLASS
AS OF AUGUST 6, 2008
FirstEnergy Corp., $0.10 par value
304,835,407
FirstEnergy Solutions Corp., no par value
7
Ohio Edison Company, no par value
60
The Cleveland Electric Illuminating Company, no par value
67,930,743
The Toledo Edison Company, $5 par value
29,402,054
Jersey Central Power & Light Company, $10 par value
14,421,637
Metropolitan Edison Company, no par value
859,500
Pennsylvania Electric Company, $20 par value
4,427,577

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

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

OMISSION OF CERTAIN INFORMATION

FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.

 
 

 

Forward-Looking Statements: This Form 10-Q includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements include declarations regarding management’s intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “believe,” “estimate” and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievement expressed or implied by such forward-looking statements.

Actual results may differ materially due to:
·  
the speed and nature of increased competition in the electric utility industry and legislative and regulatory changes affecting how generation rates will be determined following the expiration of existing rate plans in Ohio and Pennsylvania,
·  
the impact of the PUCO’s rulemaking process on the Ohio Companies’ ESP and MRO filings,
·  
economic or weather conditions affecting future sales and margins,
·  
changes in markets for energy services,
·  
changing energy and commodity market prices and availability,
·  
replacement power costs being higher than anticipated or inadequately hedged,
·  
the continued ability of FirstEnergy’s regulated utilities to collect transition and other charges or to recover increased transmission costs,
·  
maintenance costs being higher than anticipated,
·  
other legislative and regulatory changes, revised environmental requirements, including possible GHG emission regulations,
·  
the impact of the U.S. Court of Appeals’ July 11, 2008 decision to vacate the CAIR rules and the scope of any laws, rules or regulations that may ultimately take their place,
·  
the uncertainty of the timing and amounts of the capital expenditures needed to, among other things, implement the Air Quality Compliance Plan (including that such amounts could be higher than anticipated) or levels of emission reductions related to the Consent Decree resolving the NSR litigation or other potential regulatory initiatives,
·  
adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or operating permits and oversight) by the NRC (including, but not limited to, the Demand for Information issued to FENOC on May 14, 2007),
·  
the timing and outcome of various proceedings before the
-  
PUCO (including, but not limited to, the distribution rate cases and the generation supply plan filing for the Ohio Companies and the successful resolution of the issues remanded to the PUCO by the Ohio Supreme Court regarding the RSP and RCP, including the deferral of fuel costs)
-  
and Met-Ed’s and Penelec’s transmission service charge filings with the PPUC as well as the resolution of the Petitions for Review filed with the Commonwealth Court of Pennsylvania with respect to the transition rate plan for Met-Ed and Penelec,
·  
the continuing availability of generating units and their ability to operate at, or near full capacity,
·  
the changing market conditions that could affect the value of assets held in the registrants’ nuclear decommissioning trusts, pension trusts and other trust funds,
·  
the ability to comply with applicable state and federal reliability standards,
·  
the ability to accomplish or realize anticipated benefits from strategic goals (including employee workforce initiatives),
·  
the ability to improve electric commodity margins and to experience growth in the distribution business,
·  
the ability to access the public securities and other capital markets and the cost of such capital,
·  
the risks and other factors discussed from time to time in the registrants’ SEC filings, and other similar factors.

The foregoing review of factors should not be construed as exhaustive. New factors emerge from time to time, and it is not possible to predict all such factors, nor assess the impact of any such factor on the registrants’ business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. Also, a security rating is not a recommendation to buy, sell or hold securities, and it may be subject to revision or withdrawal at any time and each such rating should be evaluated independently of any other rating. The registrants expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events or otherwise.








 
 

 

TABLE OF CONTENTS



   
Pages
   
Glossary of Terms
iii-v
     
Part I.     Financial Information
 
     
Items 1. and 2. - Financial Statements and Management’s Discussion and Analysis ofFinancial Condition and Results of Operations.
 
     
FirstEnergy Corp.
 
     
 
Management's Discussion and Analysis of Financial Condition and
 
 
Results of Operations
1-42
 
Report of Independent Registered Public Accounting Firm
43
 
Consolidated Statements of Income
44
 
Consolidated Statements of Comprehensive Income
45
 
Consolidated Balance Sheets
46
 
Consolidated Statements of Cash Flows
47
     
FirstEnergy Solutions Corp.
 
     
 
Management's Narrative Analysis of Results of Operations
48-50
 
Report of Independent Registered Public Accounting Firm
51
 
Consolidated Statements of Income and Comprehensive Income
52
 
Consolidated Balance Sheets
53
 
Consolidated Statements of Cash Flows
54
     
Ohio Edison Company
 
     
 
Management's Narrative Analysis of Results of Operations
55-56
 
Report of Independent Registered Public Accounting Firm
57
 
Consolidated Statements of Income and Comprehensive Income
58
 
Consolidated Balance Sheets
59
 
Consolidated Statements of Cash Flows
60
     
The Cleveland Electric Illuminating Company
 
     
 
Management's Narrative Analysis of Results of Operations
61-62
 
Report of Independent Registered Public Accounting Firm
63
 
Consolidated Statements of Income and Comprehensive Income
64
 
Consolidated Balance Sheets
65
 
Consolidated Statements of Cash Flows
66
     
The Toledo Edison Company
 
     
 
Management's Narrative Analysis of Results of Operations
67-68
 
Report of Independent Registered Public Accounting Firm
69
 
Consolidated Statements of Income and Comprehensive Income
70
 
Consolidated Balance Sheets
71
 
Consolidated Statements of Cash Flows
72
     

 
i

 

TABLE OF CONTENTS (Cont'd)



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





 
ii

 
GLOSSARY OF TERMS


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

ATSI
American Transmission Systems, Incorporated, owns and operates transmission facilities
 
CEI
The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
 
Companies
OE, CEI, TE, JCP&L, Met-Ed and Penelec
 
FENOC
FirstEnergy Nuclear Operating Company, operates nuclear generating facilities
 
FES
FirstEnergy Solutions Corp., provides energy-related products and services
 
FESC
FirstEnergy Service Company, provides legal, financial and other corporate support services
 
FGCO
FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities
 
FirstEnergy
FirstEnergy Corp., a public utility holding company
 
GPU
GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on
November 7, 2001
 
JCP&L
Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
 
JCP&L Transition
   Funding
JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition
bonds
 
JCP&L Transition
   Funding II
JCP&L Transition Funding II LLC, a Delaware limited liability company and issuer of transition bonds
 
Met-Ed
Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
 
NGC
FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities
 
OE
Ohio Edison Company, an Ohio electric utility operating subsidiary
 
Ohio Companies
CEI, OE and TE
 
Penelec
Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
 
Penn
Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
 
Pennsylvania Companies
Met-Ed, Penelec and Penn
 
PNBV
PNBV Capital Trust, a special purpose entity created by OE in 1996
 
Shippingport
Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
 
TE
The Toledo Edison Company, an Ohio electric utility operating subsidiary
 
     
The following abbreviations and acronyms are used to identify frequently used terms in this report:
 
     
ACO
Administrative Consent Order
 
AEP
American Electric Power Company, Inc.
 
ALJ
Administrative Law Judge
 
AMP-Ohio
American Municipal Power-Ohio, Inc.
 
AOCL
Accumulated Other Comprehensive Loss
 
AQC
Air Quality Control
 
ARB
Accounting Research Bulletin
 
ARO
Asset Retirement Obligation
 
ASM
Ancillary Services Market
 
BGS
Basic Generation Service
 
CAA
Clean Air Act
 
CAIR
Clean Air Interstate Rule
 
CAMR
Clean Air Mercury Rule
 
CBP
Competitive Bid Process
 
CO2
Carbon Dioxide
 
DFI
Demand for Information
DOJ
United States Department of Justice
DRA
Division of Ratepayer Advocate
EIS
Energy Independence Strategy
EITF
Emerging Issues Task Force
EMP
Energy Master Plan
EPA
United States Environmental Protection Agency
EPACT
Energy Policy Act of 2005
ESP
Electric Security Plan
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
FIN
FASB Interpretation
FIN 46R
FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities"
FIN 47
FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB
Statement No. 143"
FIN 48
FIN 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement
No. 109”

 
iii

 
GLOSSARY OF TERMS, Cont’d.


FMB
First Mortgage Bonds
FSP
FASB Staff Position
FSP FAS 157-2
FSP FAS 157-2, “Effective Date of  FASB Statement No. 157”
FTR
Financial Transmission Rights
GAAP
Accounting Principles Generally Accepted in the United States
GHG
Greenhouse Gases
ICE
Intercontinental Exchange
IRS
Internal Revenue Service
ISO
Independent System Operator
kV
Kilovolt
KWH
Kilowatt-hours
LIBOR
London Interbank Offered Rate
LOC
Letter of Credit
MEIUG
Met-Ed Industrial Users Group
MEW
Mission Energy Westside, Inc.
MISO
Midwest Independent Transmission System Operator, Inc.
Moody’s
Moody’s Investors Service
MRO
Market Rate Offer
MW
Megawatts
NAAQS
National Ambient Air Quality Standards
NERC
North American Electric Reliability Corporation
NJBPU
New Jersey Board of Public Utilities
NOPR
Notice of Proposed Rulemaking
NOV
Notice of Violation
NOX
Nitrogen Oxide
NRC
Nuclear Regulatory Commission
NSR
New Source Review
NUG
Non-Utility Generation
NUGC
Non-Utility Generation Charge
NYMEX
New York Mercantile Exchange
OCA
Office of Consumer Advocate
OTC
Over the Counter
OVEC
Ohio Valley Electric Corporation
PCAOB
Public Company Accounting Oversight Board
PCRB
Pollution Control Revenue Bond
PICA
Penelec Industrial Customer Alliance
PJM
PJM Interconnection L. L. C.
PLR
Provider of Last Resort
PPUC
Pennsylvania Public Utility Commission
PRP
Potentially Responsible Party
PSA
Power Supply Agreement
PUCO
Public Utilities Commission of Ohio
PUHCA
Public Utility Holding Company Act of 1935
RCP
Rate Certainty Plan
 
RECB
Regional Expansion Criteria and Benefits
 
RFP
Request for Proposal
 
RPM
Reliability Pricing Model
 
RSP
Rate Stabilization Plan
 
RTC
Regulatory Transition Charge
 
RTO
Regional Transmission Organization
 
S&P
Standard & Poor’s Ratings Service
 
SB221
Amended Substitute Senate Bill 221
 
SBC
Societal Benefits Charge
 
SEC
U.S. Securities and Exchange Commission
 
SECA
Seams Elimination Cost Adjustment
 
SFAS
Statement of Financial Accounting Standards
 
SFAS 109
SFAS No. 109, “Accounting for Income Taxes”
 
SFAS 123(R)
SFAS No. 123(R), "Share-Based Payment"
 
SFAS 133
SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
 
SFAS 141(R)
SFAS No 141(R), “Business Combinations”
 
SFAS 143
SFAS No. 143, “Accounting for Asset Retirement Obligations”
 
SFAS 157
SFAS No. 157, “Fair Value Measurements”
 
SFAS 159
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an
Amendment of FASB Statement No. 115”
 

 
iv

 
GLOSSARY OF TERMS, Cont’d.


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

 
v

 

PART I. FINANCIAL INFORMATION

ITEMS 1. AND 2. FINANCIAL STATEMENTS AND MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

FIRSTENERGY CORP.

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

EXECUTIVE SUMMARY

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

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

Regulatory Matters - Ohio

Legislative Process

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

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

RCP Fuel Remand

On June 3, 2008, FirstEnergy made a filing on behalf of the Ohio Companies to suspend the procedural schedule in its application to recover the companies’ 2006-2007 deferred fuel costs and associated carrying charges since its ESP filing contains a proposal addressing the recovery of these deferred fuel costs. On June 4, 2008, the PUCO Staff issued a report in accordance with its previously established procedural schedule and on June 11, 2008, the PUCO denied FirstEnergy’s request to suspend proceedings until the ESP case is completed and revised the procedural schedule. Testimony is now due August 29, 2008, and an evidentiary hearing is scheduled for September 29, 2008.
 
 
 
1

 


Regulatory Matters - Pennsylvania

Penn’s Interim Default Service Supply

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

Met-Ed and Penelec Transmission Service Charge Filing

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

Generation

Fremont Plant

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

Refueling Outage and Power Uprates

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

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

Financial Matters

New Long-Term Fuel Supply Arrangements

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


 
2

 


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

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

Refunding of Auction Rate Bonds

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

New Credit Facility

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

FIRSTENERGY’S BUSINESS

FirstEnergy is a diversified energy company headquartered in Akron, Ohio, that operates primarily through three core business segments (see Results of Operations).

·  
Energy Delivery Services transmits and distributes electricity through FirstEnergy’s eight utility operating companies, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey and purchases power for its PLR and default service requirements in Pennsylvania and New Jersey. This business segment derives its revenues principally from the delivery of electricity within FirstEnergy’s service areas at regulated rates, cost recovery of regulatory assets and the sale of electric generation service to retail customers who have not selected an alternative supplier (default service) in its Pennsylvania and New Jersey franchise areas. The segment’s net income reflects the commodity costs of securing electricity from FirstEnergy’s competitive energy services segment under partial requirements purchased power agreements with FES and from non-affiliated power suppliers, including, in each case, associated transmission costs.

·  
Competitive Energy Services supplies the electric power needs of end-use customers through retail and wholesale arrangements, including associated company power sales to meet all or a portion of the PLR and default service requirements of FirstEnergy’s Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland and Michigan. This business segment owns or leases and operates 19 generating facilities with a net demonstrated capacity of approximately 13,664 MW and also purchases electricity to meet sales obligations. The segment's net income is primarily derived from affiliated company power sales and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission and ancillary costs charged by PJM and MISO to deliver energy to the segment’s customers.

·  
Ohio Transitional Generation Services supplies the electric power needs of non-shopping customers under the default service requirements of the Ohio Companies. The segment's net income is primarily derived from electric generation sales revenues less the cost of power purchased from the competitive energy services segment through a full-requirements PSA arrangement with FES, including net transmission and ancillary costs charged by MISO to deliver energy to retail customers.

 
3

 


RESULTS OF OPERATIONS

The financial results discussed below include revenues and expenses from transactions among FirstEnergy's business segments. A reconciliation of segment financial results is provided in Note 13 to the consolidated financial statements. Net income by major business segment was as follows:


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

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

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

Financial results for FirstEnergy's major business segments in the second quarter of 2008 and 2007 were as follows:
 
               
Ohio
             
   
Energy
   
Competitive
   
Transitional
   
Other and
       
   
Delivery
   
Energy
   
Generation
   
Reconciling
   
FirstEnergy
 
Second Quarter 2008 Financial Results
 
Services
   
Services
   
Services
   
Adjustments
   
Consolidated
 
   
(In millions)
 
Revenues:
                             
External
                             
Electric
  $ 2,030     $ 324     $ 670     $ -     $ 3,024  
Other
    152       51       13       5       221  
Internal
    -       704       -       (704 )     -  
Total Revenues
    2,182       1,079       683       (699 )     3,245  
                                         
Expenses:
                                       
Fuel and purchased power
    998       537       555       (704 )     1,386  
Other operating expenses
    413       312       81       (25 )     781  
Provision for depreciation
    104       59       -       5       168  
Amortization of regulatory assets
    235       -       11       -       246  
Deferral of new regulatory assets
    (98 )     -       -       -       (98 )
General taxes
    149       24       2       5       180  
Total Expenses
    1,801       932       649       (719 )     2,663  
                                         
Operating Income
    381       147       34       20       582  
Other Income (Expense):
                                       
Investment income
    40       (8 )     (1 )     (15 )     16  
Interest expense
    (100 )     (38 )     -       (50 )     (188 )
Capitalized interest
    1       10       -       2       13  
Total Other Expense
    (59 )     (36 )     (1 )     (63 )     (159 )
                                         
Income Before Income Taxes
    322       111       33       (43 )     423  
Income taxes
    129       45       13       (27 )     160  
Net Income
  $ 193     $ 66     $ 20     $ (16 )   $ 263  

 
4

 
 

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


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

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

Revenues –

The increase in total revenues resulted from the following sources:

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


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

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

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

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

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

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

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

 
6

 


Expenses –

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

 
·
Purchased power costs were $122 million higher in the second quarter of 2008 due to higher unit costs and a decrease in the amount of NUG costs deferred. The increased unit costs reflected the effect of higher JCP&L costs resulting from the BGS auction process. However, JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. The following table summarizes the sources of changes in purchased power costs:

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

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

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

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

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

-  
reduced tree trimming expenses of $2 million.

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

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

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

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

Other Expense –

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

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

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

 
7

 


Revenues –

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

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

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

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

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

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

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


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

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

 
8

 


Expenses -

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

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

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

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

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

Partially offsetting the higher costs were:

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

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

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

Other Expense –

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

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

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

Revenues –

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

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


 
9

 


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

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

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

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

Expenses -

Purchased power costs were $18 million higher due primarily to higher unit costs for power purchased from FES. The factors contributing to the higher costs are summarized in the following table:

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

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

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

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

Other – Second Quarter 2008 Compared with Second Quarter 2007

Financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $25 million increase in FirstEnergy’s net income in the second quarter of 2008 compared to the same period in 2007. The increase primarily resulted from a $15 million litigation settlement relating to formerly-owned international assets, $6 million of interest income related to the settlement and a $9 million reduction of interest expense associated with the revolving credit facility.
.

 
10

 


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

Financial results for FirstEnergy's major business segments in the first six months of 2008 and 2007 were as follows:
 
               
Ohio
             
   
Energy
   
Competitive
   
Transitional
   
Other and
       
   
Delivery
   
Energy
   
Generation
   
Reconciling
   
FirstEnergy
 
First Six Months 2008 Financial Results
 
Services
   
Services
   
Services
   
Adjustments
   
Consolidated
 
   
(In millions)
 
Revenues:
                             
External
                             
Electric
  $ 4,080     $ 613     $ 1,361     $ -     $ 6,054  
Other
    314       91       29       34       468  
Internal
    -       1,480       -       (1,480 )     -  
Total Revenues
    4,394       2,184       1,390       (1,446 )     6,522  
                                         
Expenses:
                                       
Fuel and purchased power
    1,981       1,070       1,143       (1,480 )     2,714  
Other operating expenses
    858       621       158       (56 )     1,581  
Provision for depreciation
    210       112       -       10       332  
Amortization of regulatory assets
    484       -       20       -       504  
Deferral of new regulatory assets
    (198 )     -       (5 )     -       (203 )
General taxes
    322       56       3       14       395  
Total Expenses
    3,657       1,859       1,319       (1,512 )     5,323  
                                         
Operating Income
    737       325       71       66       1,199  
Other Income (Expense):
                                       
Investment income
    85       (14 )     -       (38 )     33  
Interest expense
    (203 )     (72 )     -       (92 )     (367 )
Capitalized interest
    1       17       -       3       21  
Total Other Expense
    (117 )     (69 )     -       (127 )     (313 )
                                         
Income Before Income Taxes
    620       256       71       (61 )     886  
Income taxes
    248       103       28       (32 )     347  
Net Income
  $ 372     $ 153     $ 43     $ (29 )   $ 539  

 
11

 

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


 
12

 

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

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

Revenues –

The increase in total revenues resulted from the following sources:

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

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

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

The decrease in electric distribution deliveries to customers was primarily due to lower weather-related usage during the first six months of 2008 compared to the same period of 2007, as cooling degree days decreased by 11% and heating degree days decreased by 2%. The lower revenues reflected the decreased distribution deliveries and the residual effects of the distribution rate decreases for Met-Ed and Penelec as a result of a January 11, 2007 PPUC rate decision (see Outlook – State Regulatory Matters – Pennsylvania).

The following table summarizes the price and volume factors contributing to the $276 million increase in generation revenues in the first six months of 2008 compared to the same period of 2007:

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

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

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

 
13

 


Expenses –

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

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

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


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

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

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

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

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

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

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

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

Other Expense –

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


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

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

 
14

 

Revenues –

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

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

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

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

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

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

   
Increase
 
Source of Change in Non-Affiliated Generation Revenues
 
(Decrease)
 
   
(In millions)
 
Retail:
       
Effect of 12.8% decrease in sales volumes
 
$
(46
)
Change in prices
   
2
 
     
(44
)
Wholesale:
       
Effect of 7.6% decrease in sales volumes
   
(21
)
Change in prices
   
43
 
     
22
 
Net Decrease in Non-Affiliated Generation Revenues
 
$
(22
)
 
   
Increase
 
Source of Change in Affiliated Generation Revenues
 
(Decrease)
 
   
(In millions)
 
Ohio Companies:
       
Effect of 0.6% decrease in sales volumes
 
$
(7
)
Change in prices
   
80
 
     
73
 
Pennsylvania Companies:
       
Effect of 2.8% increase in sales volumes
   
10
 
Change in prices
   
(7
)
     
3
 
Net Increase in Affiliated Generation Revenues
 
$
76
 

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

 
15

 


Expenses -

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

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

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

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

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

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

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

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

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

Other Expense –

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

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

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

Revenues –

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

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


 
16

 


The following table summarizes the price and volume factors contributing to the net increase in sales revenues from retail customers:
 
Source of Change in Generation Revenues
 
Increase (Decrease)
 
   
(In millions)
 
Retail:
       
Effect of 0.5% decrease in sales volumes
 
$
(5
)
Change in prices
   
108
 
 Net Increase in Retail Generation Revenues
 
$
103
 
         

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

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

Expenses -

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

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

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

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

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

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

Financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $61 million increase in FirstEnergy’s net income in the first six months of 2008 compared to the same period in 2007. The increase resulted primarily from the sale of telecommunication assets ($19 million, net of taxes), a $15 million litigation settlement relating to formerly-owned international assets and associated interest of $6 million, and a $20 million reduction of interest expense associated with the revolving credit facility.


 
17

 


CAPITAL RESOURCES AND LIQUIDITY

FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. In 2008 and in subsequent years, FirstEnergy expects to satisfy these requirements with a combination of cash from operations and funds from the capital markets. FirstEnergy also expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.

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

FirstEnergy's primary source of cash required for continuing operations as a holding company is cash from the operations of its subsidiaries. FirstEnergy and certain of its subsidiaries also have access to $2.75 billion of short-term financing under a revolving credit facility which expires in 2012. Under the terms of the facility, FirstEnergy is permitted to have up to $1.5 billion in outstanding borrowings at any time, subject to the facility cap of $2.75 billion of aggregate outstanding borrowings by it and its subsidiaries that are also parties to such facility. In the first six months of 2008, FirstEnergy received $200 million of cash dividends from its subsidiaries and paid $335 million in cash dividends to common shareholders. With the exception of Met-Ed, which is currently in an accumulated deficit position, there are no material restrictions on the payment of cash dividends by the subsidiaries of FirstEnergy.

As of June 30, 2008, FirstEnergy had $70 million of cash and cash equivalents compared with $129 million as of December 31, 2007. The major sources of changes in these balances are summarized below.
 
Cash Flows From Operating Activities

FirstEnergy's consolidated net cash from operating activities is provided primarily by its energy delivery services and competitive energy services businesses (see Results of Operations above). Net cash provided from operating activities was $316 million and $170 million in the first six months of 2008 and 2007, respectively, as summarized in the following table:

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

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

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



 
18

 


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

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

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

As of June 30, 2008, the Ohio Companies and Penn had the aggregate capability to issue approximately $3.5 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE, CEI and TE is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE, CEI and TE to incur additional secured debt not otherwise permitted by a specified exception of up to $579 million, $459 million and $124 million, respectively, as of June 30, 2008.  On June 19, 2008, FGCO established an FMB indenture. Based upon its net earnings and available bondable property additions, as of June 30, 2008, FGCO had the capability to issue $2.8 billion of additional FMB under the terms of this new indenture.

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

FirstEnergy and certain of its subsidiaries are party to a $2.75 billion revolving credit facility (included in the borrowing capability table above). FirstEnergy has the capability to request an increase in the total commitments available under this facility up to a maximum of $3.25 billion. Commitments under the facility are available until August 24, 2012, unless the lenders agree, at the request of the borrowers, to an unlimited number of additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each borrower are subject to a specified sub-limit, as well as applicable regulatory and other limitations.

 
19

 

The following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations:

   
Revolving
 
Regulatory and
 
   
Credit Facility
 
Other Short-Term
 
Borrower
 
Sub-Limit
 
Debt Limitations(1)
 
   
(In millions)
 
FirstEnergy
 
$
2,750
 
$
-
(2)
OE
   
500
   
500
 
Penn
   
50
   
39
(3)
CEI
   
250
(4)
 
500
 
TE
   
250
(4)
 
500
 
JCP&L
   
425
   
428
(3)
Met-Ed
   
250
   
300
(3)
Penelec
   
250
   
300
(3)
FES
   
1,000
   
-
(2)
ATSI
   
-
(5)
 
50
 
               
(1)As of June 30, 2008.
(2)No regulatory approvals, statutory or charter limitations applicable.
(3)Excluding amounts which may be borrowed under the regulated companies’ money pool.
(4)Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice to the administrative agent that such borrower has senior unsecured debt ratings of at least BBB by S&P and Baa2 by Moody’s.
 (5)The borrowing sub-limit for ATSI may be increased up to $100 million by delivering notice to the administrative agent that either (i) ATSI has senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody’s or (ii) FirstEnergy has guaranteed ATSI’s obligations of such borrower under the facility.
 

The revolving credit facility, combined with the $300 million and $100 million facilities referenced in the footnote to the borrowing capability table above and an aggregate $550 million ($294 million unused as of June 30, 2008) of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are used to provide liquidity to meet working capital requirements and for other general corporate purposes for FirstEnergy and its subsidiaries.

Under the revolving credit facility, borrowers may request the issuance of LOCs expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit.

The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of June 30, 2008, FirstEnergy’s and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:

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

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

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

 
20

 

FirstEnergy's regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy's unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first six months of 2008 was 3.24% for the regulated companies’ money pool and 3.21% for the unregulated companies’ money pool.

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

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

Cash Flows From Investing Activities

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

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

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

 
21

 


During the second half of 2008, capital requirements for property additions and capital leases are expected to be approximately $938 million. FirstEnergy and the Companies have additional requirements of approximately $151 million for maturing long-term debt during the remainder of 2008. These cash requirements are expected to be satisfied from a combination of internal cash, short-term credit arrangements and funds raised in the capital markets.

FirstEnergy's capital spending for the period 2008-2012 is expected to be approximately $7.6 billion (excluding nuclear fuel), of which approximately $2.1 billion applies to 2008. Investments for additional nuclear fuel during the 2008-2012 period are estimated to be approximately $1.2 billion, of which about $171 million applies to 2008. During the same periods, FirstEnergy's nuclear fuel investments are expected to be reduced by approximately $895 million and $111 million, respectively, as the nuclear fuel is consumed.

GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. Some of the guaranteed contracts contain collateral provisions that are contingent upon FirstEnergy’s credit ratings.

As of June 30, 2008, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.3 billion, as summarized below:

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

(1)
Issued for open-ended terms, with a 10-day termination right by FirstEnergy.
(2)
Reflects the interest coverage portion of LOCs issued in support of floating-rate
PCRBs with various maturities. The principal amount of floating-rate PCRBs of
$2.1 billion is reflected in debt on FirstEnergy’s consolidated balance sheets.
(3)
Includes guarantees of $300 million for OVEC obligations and $80 million for
nuclear decommissioning funding assurances.
(4)
Includes $50 million issued for various terms pursuant to LOC capacity available
under FirstEnergy’s revolving credit facility.
(5)
Includes approximately $182 million pledged in connection with the sale and
leaseback of Beaver Valley Unit 2 by CEI and TE, $291 million pledged in
connection with the sale and leaseback of Beaver Valley Unit 2 by OE and
$134 million pledged in connection with the sale and leaseback of Perry Unit 1 by OE.

 
22

 


FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financings where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with ongoing energy and energy-related activities.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event”, the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. As of June 30, 2008, FirstEnergy’s exposure under these collateral provisions was $542 million.

Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

OFF-BALANCE SHEET ARRANGEMENTS

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

FirstEnergy has equity ownership interests in certain businesses that are accounted for using the equity method of accounting for investments. There are no undisclosed material contingencies related to these investments. Certain guarantees that FirstEnergy does not expect to have a material current or future effect on its financial condition, liquidity or results of operations are disclosed under “Guarantees and Other Assurances” above.

MARKET RISK INFORMATION

FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy's Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.

Commodity Price Risk

FirstEnergy is exposed to financial and market risks resulting from the fluctuation of interest rates and commodity prices -- electricity, energy transmission, natural gas, coal, nuclear fuel and emission allowances. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. Derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of FirstEnergy’s derivative hedging contracts qualify for the normal purchase and normal sale exception under SFAS 133 and are therefore excluded from the tables below. Contracts that are not exempt from such treatment include certain power purchase agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policies Act of 1978. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs. The changes in the fair value of commodity derivative contracts related to energy production during the three months and six months ended June 30, 2008 are summarized in the following table:

 
23

 


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

(1)
Includes $616 million in non-hedge commodity derivative contracts (primarily with NUGs) that are offset by a regulatory asset.
(2)
Interest rate swaps are treated as cash flow or fair value hedges (see Interest Rate Swap Agreements below).
(3)
Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions.

Derivatives are included on the Consolidated Balance Sheet as of June 30, 2008 as follows:

Balance Sheet Classification
 
Non-Hedge
 
Hedge
 
Total
 
   
(In millions)
 
Current-
             
Other assets
 
$
1
 
$
78
 
$
79
 
Other liabilities
   
-
   
(108
)
 
(108
)
                     
Non-Current-
                   
Other deferred charges
   
27
   
11
   
38
 
Other non-current liabilities
   
(644
)
 
(15
)
 
(659
)
                     
Net liabilities
 
$
(616
)
$
(34
)
$
(650
)
 
The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 4). Sources of information for the valuation of commodity derivative contracts as of June 30, 2008 are summarized by year in the following table:

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

(1)     For the last two quarters of 2008.
(2)     Represents exchange traded NYMEX futures and options.
(3)     Primarily represents contracts based on broker and ICE quotes.
    (4)     Includes $616 million in non-hedge commodity derivative contracts (primarily with NUGs) that are offset by a regulatory asset.

 
24

 


FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on its derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of June 30, 2008. Based on derivative contracts held as of June 30, 2008, an adverse 10% change in commodity prices would decrease net income by approximately $8 million during the next 12 months.

Interest Rate Swap Agreements - Fair Value Hedges

FirstEnergy utilizes fixed-for-floating interest rate swap agreements as part of its ongoing effort to manage the interest rate risk associated with its debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues – protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates and interest payment dates match those of the underlying obligations. As of June 30, 2008, the debt underlying the $150 million outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 5.5%, which the swaps have converted to a current weighted average variable rate of 4.4%.

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


Forward Starting Swap Agreements - Cash Flow Hedges

FirstEnergy utilizes forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with anticipated future issuances of fixed-rate, long-term debt securities for one or more of its consolidated subsidiaries in 2008 and 2009, and anticipated variable-rate, short-term debt. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury and LIBOR rates between the date of hedge inception and the date of the debt issuance. During the first six months of 2008, FirstEnergy entered into forward swaps with an aggregate notional value of $850 million and terminated forward swaps with an aggregate notional value of $650 million. FirstEnergy paid $14 million in cash related to the terminations, $5 million of which was deemed ineffective and recognized in current period earnings. The remaining effective portion will be recognized over the terms of the associated future debt. As of June 30, 2008, FirstEnergy had outstanding forward swaps with an aggregate notional amount of $600 million and an aggregate fair value of $6 million.

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

Equity Price Risk

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

CREDIT RISK

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

 
25

 


FirstEnergy maintains credit policies with respect to its counterparties to manage overall credit risk.  This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure.  As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB+ (S&P).  As of June 30, 2008, the largest credit concentration was with one party, currently rated investment grade that represented 9.3% of FirstEnergy’s total approved credit risk.  Within FirstEnergy’s unregulated energy subsidiaries, 98% of credit exposures, net of collateral and reserve, were with investment-grade counterparties as of June 30, 2008.

OUTLOOK

State Regulatory Matters

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

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

The Companies and ATSI recognize, as regulatory assets, costs which the FERC, the PUCO, the PPUC and the NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $129 million as of June 30, 2008 (JCP&L - $73 million and Met-Ed - $56 million). Regulatory assets not earning a current return (primarily for certain regulatory transition costs and employee postretirement benefits) are expected to be recovered by 2014 for JCP&L and by 2020 for Met-Ed. The following table discloses regulatory assets by company:

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

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


 
26

 


Regulatory assets by source are as follows:

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


Reliability Initiatives

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

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

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

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

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

 
27

 


Ohio

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

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

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

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

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

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

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

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

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

 
28

 

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

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

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

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

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

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

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

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

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

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

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

Pennsylvania

Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. The fixed price under the agreement is expected to remain below wholesale market prices during the term of the agreement. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for their fixed income securities. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC.

 
29

 


Met-Ed and Penelec made a comprehensive transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of merger savings, with the comprehensive transition rate filing case.

The PPUC entered its opinion and order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes to NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission costs. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million).

On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. From June through October 2007, initial responsive and reply briefs were filed by various parties. Oral arguments are scheduled to take place in September 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the results of operations of Met-Ed, Penelec and FirstEnergy.

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

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

 
30

 


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

New Jersey

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of June 30, 2008, the accumulated deferred cost balance totaled approximately $293 million.

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

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

New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated through the creation of a number of working groups to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. In addition, public stakeholder meetings were held in 2006, 2007 and the first half of 2008.

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

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

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

 
31

 


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

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

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

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

FERC Matters

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or “SECA”) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC by year-end 2008.  In the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order.

PJM Transmission Rate Design

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

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

 
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Post Transition Period Rate Design

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

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

Distribution of MISO Network Service Revenues

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

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

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

MISO Ancillary Services Market and Balancing Area Consolidation

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

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

Interconnection Agreement with AMP-Ohio

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

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

Duquesne’s Request to Withdraw from PJM

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

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

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

Complaint against PJM RPM Auction

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

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

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

MISO Resource Adequacy Proposal

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

Organized Wholesale Power Markets

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

 
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Environmental Matters

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergy with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FirstEnergy estimates capital expenditures for environmental compliance of approximately $1.4 billion for the period 2008-2012.

FirstEnergy accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in FirstEnergy’s determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.

Clean Air Act Compliance

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

The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the CAA. FirstEnergy has disputed those alleged violations based on its CAA permit, the Ohio SIP and other information provided to the EPA at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding emission limits applicable to the common stack for Bay Shore Units 2, 3 and 4.

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

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

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

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

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

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

National Ambient Air Quality Standards

In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR would have required reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2), ultimately capping SO2 emissions in affected states to just 2.5 million tons annually and NOX emissions to just 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” The court ruling also vacated the CAIR regional cap-and-trade programs for SO2 and NOX, which is currently not expected to, but may, materially impair the value of emissions allowances obtained for future compliance. The future cost of compliance with these regulations may be substantial and will depend on the action taken by the EPA or Congress in response to the Court’s ruling.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the court vacated the CAMR ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA petitioned for rehearing by the entire court, which denied the petition on May 20, 2008.  The EPA must now petition for United States Supreme Court review of that ruling or take regulatory action to promulgate new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with mercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately implemented.

Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant, FirstEnergy’s only Pennsylvania coal-fired power plant, until 2015, if at all.

W. H. Sammis Plant

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

 
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On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergy could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree are currently estimated to be $1.3 billion for 2008-2012 ($650 million of which is expected to be spent during 2008, with the largest portion of the remaining $650 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 2012. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. Also, in an April 16, 2008 speech, President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition, the EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level.  At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the Senate Environmental and Public Works Committees have passed one such bill. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. On July 11, 2008, the EPA released an Advance Notice of Proposed Rulemaking, soliciting input from the public on the effects of climate change and the potential ramifications of regulation of CO2 under the CAA.

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

Clean Water Act

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

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

Regulation of Hazardous Waste

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

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of June 30, 2008, FirstEnergy had approximately $2.0 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seeks for these facilities.

The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site may be liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of June 30, 2008, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $95 million (JCP&L - $68 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through June 30, 2008. Included in the total for JCP&L are accrued liabilities of approximately $57 million for environmental remediation of former manufactured gas plants in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

Other Legal Proceedings

Power Outages and Related Litigation

In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four of New Jersey’s electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory.

 
39

 


In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007.  Proceedings are continuing in the Superior Court and a case management conference with the presiding Judge was held on June 13, 2008.  At that conference, the plaintiffs stated their intent to drop their efforts to create a class-wide damage model and, instead of dismissing the class action, expressed their desire for a bifurcated trial on liability and damages.  The judge directed the plaintiffs to indicate, on or before August 22, 2008, how they intend to proceed under this scenario.  Thereafter, the judge expects to hold another pretrial conference to address plaintiffs' proposed procedure. FirstEnergy is defending this action but is unable to predict the outcome of this matter.  No liability has been accrued as of June 30, 2008.

Nuclear Plant Matters

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

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


Other Legal Matters

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

 
40

 


On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members. On April 5, 2007, the Court rejected the plaintiffs’ request to certify this case as a class action and, accordingly, did not appoint the plaintiffs as class representatives or their counsel as class counsel. On July 30, 2007, plaintiffs’ counsel voluntarily withdrew their request for reconsideration of the April 5, 2007 Court order denying class certification and the Court heard oral argument on the plaintiffs’ motion to amend their complaint, which OE opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend their complaint. The plaintiffs have appealed the Court’s denial of the motion for certification as a class action and motion to amend their complaint.

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

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

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

FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

SFAS 141(R) – “Business Combinations”

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

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

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

 
41

 


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

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

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

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


 
42

 



Report of Independent Registered Public Accounting Firm








To the Stockholders and Board of
Directors of FirstEnergy Corp.:

We have reviewed the accompanying consolidated balance sheet of FirstEnergy Corp. and its subsidiaries as of June 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2008 and 2007 and the consolidated statement of cash flows for the six-month periods ended June 30, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States).  A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters.  It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole.  Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
 
 
 
PricewaterhouseCoopers LLP
Cleveland, Ohio
August 7, 2008



 
 
43

 


 

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

 
44

 
 

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

 
45

 

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

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

 
47

 



FIRSTENERGY SOLUTIONS CORP.

MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS


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

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

Results of Operations

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

Revenues

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

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

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

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

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

 
48

 


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

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

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

Expenses

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

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

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

 
49

 


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

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

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

Other Expense

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

Legal Proceedings

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

New Accounting Standards and Interpretations

See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to FES.



 
50

 



Report of Independent Registered Public Accounting Firm








To the Stockholder and Board of
Directors of FirstEnergy Solutions Corp.:

We have reviewed the accompanying consolidated balance sheet of FirstEnergy Solutions Corp. and its subsidiaries as of June 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2008 and 2007 and the consolidated statement of cash flows for the six-month periods ended June 30, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States).  A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters.  It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole.  Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
 
 
 
PricewaterhouseCoopers LLP
Cleveland, Ohio
August 7, 2008



 
51

 

 

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

 
52

 
 

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

 
53

 

 

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

 
54

 

OHIO EDISON COMPANY

MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS


OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. They provide generation services to those customers electing to retain OE and Penn as their power supplier. OE’s power supply requirements are provided by FES – an affiliated company. Penn purchases power from FES and third-party suppliers through a competitive RFP process.

Results of Operations
 
In the first six months of 2008, net income decreased to $93 million from $100 million in the same period of 2007. The decrease primarily resulted from a decrease in the deferral of new regulatory assets and lower investment income, partially offset by higher electric sales revenues and lower purchased power costs.
 
Revenues
 
Revenues increased by $40 million, or 3.3%, in the first six months of 2008 compared with the same period in 2007, primarily due to increases in retail generation revenues ($26 million) and distribution throughput revenues ($13 million).

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

Changes in retail generation sales and revenues in the first six months of 2008 from the same period in 2007 are summarized in the following tables:
 
Retail Generation KWH Sales
 
Decrease
 
         
Residential
   
(1.4)
%
Commercial
   
(2.7)
%
Industrial
   
(4.9)
%
Decrease in Generation Sales
   
(2.9)
%

Retail Generation Revenues
 
Increase
 
   
(In millions)
 
Residential
 
$
14
 
Commercial
   
3
 
Industrial
   
9
 
Increase in Generation Revenues
 
$
26
 
 
Revenues from distribution throughput increased by $13 million in the first six months of 2008 compared to the same period in 2007 due to higher average unit prices for all customer classes, partially offset by lower KWH deliveries to all sectors. The higher average prices resulted from a transmission rider increase effective July 1, 2007. The lower KWH deliveries to residential and commercial customers reflected the milder weather conditions described above.

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

 
55

 


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

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

Expenses

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

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

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

Other Income

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

Legal Proceedings

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

New Accounting Standards and Interpretations

See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to OE.

 
56

 



Report of Independent Registered Public Accounting Firm








To the Stockholder and Board of
Directors of Ohio Edison Company:

We have reviewed the accompanying consolidated balance sheet of Ohio Edison Company and its subsidiaries as of June 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2008 and 2007 and the consolidated statement of cash flows for the six-month periods ended June 30, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States).  A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters.  It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole.  Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
 
 
 
PricewaterhouseCoopers LLP
Cleveland, Ohio
August 7, 2008


 
57

 

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

 
58

 
 

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

 
59

 


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

 
60

 


 
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
 
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS


CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in northeastern Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain CEI as their power supplier. CEI’s power supply requirements are primarily provided by FES – an affiliated company.

Results of Operations

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

Revenues

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

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

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

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

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


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

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

 
61

 


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

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


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

Expenses

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

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

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

Other Expense

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

Legal Proceedings

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

New Accounting Standards and Interpretations

See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to CEI.

.

62

 

 
Report of Independent Registered Public Accounting Firm









To the Stockholder and Board of Directors of
The Cleveland Electric Illuminating Company:

We have reviewed the accompanying consolidated balance sheet of The Cleveland Electric Illuminating Company and its subsidiaries as of June 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2008 and 2007 and the consolidated statement of cash flows for the six-month periods ended June 30, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States).  A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters.  It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole.  Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
 
 
 
PricewaterhouseCoopers LLP
Cleveland, Ohio
August 7, 2008



 
63

 

 

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

 
64

 


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

 
65

 


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


 
66

 


THE TOLEDO EDISON COMPANY

MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS


TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain TE as their power supplier. TE’s power supply requirements are provided by FES – an affiliated company.

Results of Operations

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

Revenues

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

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

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

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

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

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

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

 
67

 


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

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

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

Expenses

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

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

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

Other Expense

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

Legal Proceedings

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

New Accounting Standards and Interpretations

See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to TE.

.

68

 

 
Report of Independent Registered Public Accounting Firm








To the Stockholder and Board of
Directors of The Toledo Edison Company:

We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of June 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2008 and 2007 and the consolidated statement of cash flows for the six-month periods ended June 30, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States).  A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters.  It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole.  Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
 
 
 
PricewaterhouseCoopers LLP
Cleveland, Ohio
August 7, 2008



 
69

 



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

 
70

 


THE TOLEDO EDISON COMPANY
 
             
CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
 
June 30,
   
December 31,
 
   
2008
   
2007
 
 
(In thousands)
 
ASSETS
           
CURRENT ASSETS:
           
Cash and cash equivalents
  $ 22     $ 22  
Receivables-
               
Customers
    1,251       449  
Associated companies
    13,465       88,796  
Other (less accumulated provisions of $174,000 and $615,000,
         
respectively, for uncollectible accounts)
    9,901       3,116  
Notes receivable from associated companies
    56,912       154,380  
Prepayments and other
    1,157       865  
      82,708       247,628  
UTILITY PLANT:
               
In service
    852,806       931,263  
Less - Accumulated provision for depreciation
    397,496       420,445  
      455,310       510,818  
Construction work in progress
    6,111       19,740  
      461,421       530,558  
OTHER PROPERTY AND INVESTMENTS:
               
Investment in lessor notes
    142,687       154,646  
Long-term notes receivable from associated companies
    37,384       37,530  
Nuclear plant decommissioning trusts
    68,002       66,759  
Other
    1,712       1,756  
      249,785       260,691  
DEFERRED CHARGES AND OTHER ASSETS:
               
Goodwill
    500,576       500,576  
Regulatory assets
    171,030       203,719  
Pension assets
    30,240       28,601  
Property taxes
    21,010       21,010  
Other
    62,686       20,496  
      785,542       774,402  
    $ 1,579,456     $ 1,813,279  
LIABILITIES AND CAPITALIZATION
               
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $ 34     $ 34  
Accounts payable-
               
Associated companies
    44,205       245,215  
Other
    4,339       4,449  
Notes payable to associated companies
    34,954       13,396  
Accrued taxes
    22,322       30,245  
Lease market valuation liability
    36,900       36,900  
Other
    15,256       22,747  
      158,010       352,986  
CAPITALIZATION:
               
Common stockholder's equity-
               
Common stock, $5 par value, authorized 60,000,000 shares -
         
29,402,054 shares outstanding
    147,010       147,010  
Other paid-in capital
    173,170       173,169  
Accumulated other comprehensive loss
    (11,067 )     (10,606 )
Retained earnings
    213,940       175,618  
Total common stockholder's equity
    523,053       485,191  
Long-term debt and other long-term obligations
    303,386       303,397  
      826,439       788,588  
NONCURRENT LIABILITIES:
               
Accumulated deferred income taxes
    100,308       103,463  
Accumulated deferred investment tax credits
    9,753       10,180  
Lease market valuation liability
    291,550       310,000  
Retirement benefits
    65,291       63,215  
Asset retirement obligations
    29,225       28,366  
Deferred revenues - electric service programs
    6,622       12,639  
Lease assignment payable to associated companies
    28,835       83,485  
Other
    63,423       60,357  
      595,007       671,705  
COMMITMENTS AND CONTINGENCIES (Note 10)
               
    $ 1,579,456     $ 1,813,279  
                 
The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company
 
are an integral part of these balance sheets.
               

 
71

 


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

 
72

 
 
JERSEY CENTRAL POWER & LIGHT COMPANY
 
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS


JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts business in New Jersey, providing regulated electric transmission and distribution services. JCP&L also provides generation services to those customers electing to retain JCP&L as their power supplier.

Results of Operations

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

Revenues

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

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

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

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

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


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

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

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

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

 
73

 


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

Expenses

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

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

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

Other Expenses

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

Sale of Investment

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

Legal Proceedings

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

New Accounting Standards and Interpretations

See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to JCP&L.



 
74

 



Report of Independent Registered Public Accounting Firm








To the Stockholder and Board of
Directors of Jersey Central Power & Light Company:

We have reviewed the accompanying consolidated balance sheet of Jersey Central Power & Light Company and its subsidiaries as of June 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2008 and 2007 and the consolidated statement of cash flows for the six-month periods ended June 30, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States).  A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters.  It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole.  Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
 
 
 
PricewaterhouseCoopers LLP
Cleveland, Ohio
August 7, 2008



 
75

 


 

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

 
76

 
 

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

 
77

 


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

 
78

 


METROPOLITAN EDISON COMPANY
 
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS


Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also provides generation service to those customers electing to retain Met-Ed as their power supplier.

Results of Operations

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

Revenues

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

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

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

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

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


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

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

 
79

 


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

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

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

Operating Expenses

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

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

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

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

Other Expense

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

Legal Proceedings

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

New Accounting Standards and Interpretations

See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to Met-Ed.

 
80

 



Report of Independent Registered Public Accounting Firm








To the Stockholder and Board of
Directors of Metropolitan Edison Company:

We have reviewed the accompanying consolidated balance sheet of Metropolitan Edison Company and its subsidiaries as of June 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2008 and 2007 and the consolidated statement of cash flows for the six-month periods ended June 30, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States).  A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters.  It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole.  Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
 
 
 
PricewaterhouseCoopers LLP
Cleveland, Ohio
August 7, 2008



 
81

 


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

 
82

 


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

 
83

 


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

 
84

 


PENNSYLVANIA ELECTRIC COMPANY
 
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS


Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern and south central Pennsylvania, providing regulated transmission and distribution services. Penelec also provides generation services to those customers electing to retain Penelec as their power supplier.

Results of Operations

Net income decreased to $40 million in the first six months of 2008, compared to $51 million in the same period of 2007. The decrease was primarily due to increased purchased power costs, net amortization of regulatory assets and interest expense, partially offset by higher revenues.

Revenues

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

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

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

Retail Generation KWH Sales
 
Increase
 
       
Residential
   
1.5
 %
Commercial
   
1.5
 %
Industrial
   
0.3
 %
    Increase in Retail Generation Sales
   
1.1
 %
 
       
Retail Generation Revenues
 
Increase
 
   
(In millions)
 
Residential
 
$
2
 
Commercial
   
3
 
Industrial
   
1
 
    Increase in Retail Generation Revenues
 
$
6
 


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

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

 
85

 


Distribution KWH Deliveries
 
Increase
 
       
Residential
   
1.5
 %
Commercial
   
1.5
 %
Industrial
   
2.9
 %
    Increase in Distribution Deliveries
   
2.0
 %
 
Distribution Revenues
 
Increase
(Decrease)
 
   
(In millions)
 
Residential
 
$
1
 
Commercial
   
2
 
Industrial
   
(1
)
    Net Increase in Distribution Revenues
 
$
2
 

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

Operating Expenses

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

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

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

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

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

Other Expense

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

Legal Proceedings

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

New Accounting Standards and Interpretations

See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to Penelec.

 
86

 



Report of Independent Registered Public Accounting Firm








To the Stockholder and Board of
Directors of Pennsylvania Electric Company:

We have reviewed the accompanying consolidated balance sheet of Pennsylvania Electric Company and its subsidiaries as of June 30, 2008 and the related consolidated statements of income and comprehensive income for each of the three-month and six-month periods ended June 30, 2008 and 2007 and the consolidated statement of cash flows for the six-month periods ended June 30, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States).  A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters.  It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole.  Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows for the year then ended (not presented herein), and in our report dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
 
 
 
PricewaterhouseCoopers LLP
Cleveland, Ohio
August 7, 2008



 
87

 


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

 
88

 

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

 
89

 

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


 
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COMBINED MANAGEMENT’S DISCUSSION
AND ANALYSIS OF REGISTRANT SUBSIDIARIES


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

Regulatory Matters (Applicable to each of the Companies)

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

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

The Companies and ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $129 million as of June 30, 2008 (JCP&L - $73 million and Met-Ed - $56 million). Regulatory assets not earning a current return are expected to be recovered by 2014 for JCP&L and by 2020 for Met-Ed. The following table discloses regulatory assets by company:

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

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


 
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Ohio (Applicable to OE, CEI and TE)

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. The fixed price under the agreement is expected to remain below wholesale market prices during the term of the agreement. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for their fixed income securities. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC.

 
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Met-Ed and Penelec made a comprehensive transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of merger savings, with the comprehensive transition rate filing case.

The PPUC entered its opinion and order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes to NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission costs. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million).

On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. From June through October 2007, initial responsive and reply briefs were filed by various parties. Oral arguments are scheduled to take place in September 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the results of operations of Met-Ed and Penelec.

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

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

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

New Jersey (Applicable to JCP&L)

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of June 30, 2008, the accumulated deferred cost balance totaled approximately $293 million.

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

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

New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated through the creation of a number of working groups to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. In addition, public stakeholder meetings were held in 2006, 2007 and the first half of 2008.

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

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

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

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

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

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

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

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

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or “SECA”) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC by year-end 2008.  In the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order.

PJM Transmission Rate Design

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

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

 
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Post Transition Period Rate Design

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

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

Distribution of MISO Network Service Revenues

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

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

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

MISO Ancillary Services Market and Balancing Area Consolidation

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

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

Interconnection Agreement with AMP-Ohio

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

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

Duquesne’s Request to Withdraw from PJM

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

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

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

Complaint against PJM RPM Auction

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

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

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

MISO Resource Adequacy Proposal

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

Organized Wholesale Power Markets

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

 
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Environmental Matters

Various federal, state and local authorities regulate FES and the Companies with regard to air and water quality and other environmental matters. The effects of compliance on FES and the Companies with regard to environmental matters could have a material adverse effect on their earnings and competitive position to the extent that they compete with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FES estimates capital expenditures for environmental compliance of approximately $1.4 billion for the period 2008-2012.

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

Clean Air Act Compliance (Applicable to FES)

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

The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the CAA. FES has disputed those alleged violations based on its CAA permit, the Ohio SIP and other information provided to the EPA at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding emission limits applicable to the common stack for Bay Shore Units 2, 3 and 4.

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

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

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

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

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

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

National Ambient Air Quality Standards (Applicable to FES)

In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR would have required reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2), ultimately capping SO2 emissions in affected states to just 2.5 million tons annually and NOX emissions to just 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” The court ruling also vacated the CAIR regional cap and trade programs for SO2 and NOX, which is currently not expected to, but may, materially impair the value of emissions allowances obtained for future compliance. The future cost of compliance with these regulations may be substantial and will depend on the action taken by the EPA or Congress in response to the Court’s ruling.

Mercury Emissions (Applicable to FES)

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the court vacated the CAMR ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA petitioned for rehearing by the entire court, which denied the petition on May 20, 2008.  The EPA must now petition for United States Supreme Court review of that ruling or take regulatory action to promulgate new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with mercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately implemented.

Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant, FES’ only Pennsylvania coal-fired power plant, until 2015, if at all.

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

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

On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergy could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree are currently estimated to be $1.3 billion for 2008-2012 for FGCO ($650 million of which is expected to be spent during 2008, with the largest portion of the remaining $650 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above.

Climate Change (Applicable to FES)

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 2012. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. Also, in an April 16, 2008 speech, President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition, the EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level.  At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the Senate Environmental and Public Works Committees have passed one such bill. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. On July 11, 2008, the EPA released an Advance Notice of Proposed Rulemaking, soliciting input from the public on the effects of climate change and the potential ramifications of regulation of CO2 under the CAA.

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

Clean Water Act (Applicable to FES)

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

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

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

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

Under NRC regulations, FES and the Companies must ensure that adequate funds will be available to decommission their nuclear facilities. As of June 30, 2008, FES and the Companies had approximately $2.0 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seeks for these facilities.

The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site may be liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of June 30, 2008, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $95 million (JCP&L - $68 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through June 30, 2008. Included in the total for JCP&L are accrued liabilities of approximately $57 million for environmental remediation of former manufactured gas plants in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

Other Legal Proceedings

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

In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four of New Jersey’s electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory.

 
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In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007.  Proceedings are continuing in the Superior Court and a case management conference with the presiding Judge was held on June 13, 2008.  At that conference, the plaintiffs stated their intent to drop their efforts to create a class-wide damage model and, instead of dismissing the class action, expressed their desire for a bifurcated trial on liability and damages.  The judge directed the plaintiffs to indicate, on or before August 22, 2008, how they intend to proceed under this scenario.  Thereafter, the judge expects to hold another pretrial conference to address plaintiffs' proposed procedure. JCP&L is defending this action but is unable to predict the outcome of this matter.  No liability has been accrued as of June 30, 2008.

Nuclear Plant Matters (Applicable to FES)

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

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

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

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

 
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On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members. On April 5, 2007, the Court rejected the plaintiffs’ request to certify this case as a class action and, accordingly, did not appoint the plaintiffs as class representatives or their counsel as class counsel. On July 30, 2007, plaintiffs’ counsel voluntarily withdrew their request for reconsideration of the April 5, 2007 Court order denying class certification and the Court heard oral argument on the plaintiffs’ motion to amend their complaint, which OE opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend their complaint. The plaintiffs have appealed the Court’s denial of the motion for certification as a class action and motion to amend their complaint.

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

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

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

FES and the Companies accrue legal liabilities only when they conclude that it is probable that they have an obligation for such costs and can reasonably estimate the amount of such costs. If it were ultimately determined that FES and the Companies have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect their financial condition, results of operations and cash flows.

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

SFAS 141(R) – “Business Combinations”

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

 
105

 


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

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

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

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

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

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


 
106

 


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


1.  ORGANIZATION AND BASIS OF PRESENTATION

FirstEnergy is a diversified energy company that holds, directly or indirectly, all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, FES and its subsidiaries FGCO and NGC, and FESC.

FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, the FERC and, as applicable, the PUCO, the PPUC and the NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period.

These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 2007 for FirstEnergy, FES and the Companies. The consolidated unaudited financial statements of FirstEnergy, FES and each of the Companies reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform to the current year presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.

FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 8) when it is determined to be the VIE's primary beneficiary. Investments in non-consolidated affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control (20-50% owned companies, joint ventures and partnerships) follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income.

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

2.  EARNINGS PER SHARE

Basic earnings per share of common stock is computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. The pool of stock-based compensation tax benefits is calculated in accordance with SFAS 123(R). On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding common stock through an accelerated share repurchase program at an initial price of approximately $900 million. A final purchase price adjustment of $51 million was settled in cash on December 13, 2007. The following table reconciles basic and diluted earnings per share of common stock:

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

3.  DIVESTITURES AND DISCONTINUED OPERATIONS

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

4.  FAIR VALUE MEASURES

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

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

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

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

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

 
108

 


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

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

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

(1)  
Balance excludes $2 million of net receivables, payables and accrued income.
(2)  
Excludes $312 million of the cash surrender value of life insurance contracts.
(3)  
NUG contracts are completely offset by regulatory assets.

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

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

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

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

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


 
109

 

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

5.  DERIVATIVE INSTRUMENTS

FirstEnergy is exposed to financial risks resulting from the fluctuation of interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility relating to these exposures, FirstEnergy uses a variety of derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. FirstEnergy's Risk Policy Committee, comprised of members of senior management, provides general management oversight for risk management activities throughout FirstEnergy. They are responsible for promoting the effective design and implementation of sound risk management programs. They also oversee compliance with corporate risk management policies and established risk management practices.

FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheet at their fair value unless they meet the normal purchases and normal sales criteria. Derivatives that meet those criteria are accounted for at cost. The changes in the fair value of derivative instruments that do not meet the normal purchases and normal sales criteria are recorded as other expense, as AOCL, or as part of the value of the hedged item, depending on whether or not it is designated as part of a hedge transaction, the nature of the hedge transaction and hedge effectiveness. FirstEnergy does not offset fair value for the right to reclaim collateral or the obligation to return collateral.

FirstEnergy hedges anticipated transactions using cash flow hedges. Such transactions include hedges of anticipated electricity and natural gas purchases and anticipated interest payments associated with future debt issues. The effective portion of such hedges are initially recorded in equity as other comprehensive income or loss and are subsequently included in net income as the underlying hedged commodities are delivered or interest payments are made. Gains and losses from any ineffective portion of cash flow hedges are included directly in earnings.

The net deferred losses of $78 million included in AOCL as of June 30, 2008, for derivative hedging activity, as compared to $75 million as of December 31, 2007, resulted from a net $15 million increase related to current hedging activity and a $12 million decrease due to net hedge losses reclassified to earnings during the six months ended June 30, 2008. Based on current estimates, approximately $28 million (after tax) of the net deferred losses on derivative instruments in AOCL as of June 30, 2008 are expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuate from period to period based on various market factors.

FirstEnergy has entered into swaps that have been designated as fair value hedges of fixed-rate, long-term debt issues to protect against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates received, and interest payment dates match those of the underlying debt obligations. As of June 30, 2008, FirstEnergy had interest rate swaps with an aggregate notional value of $150 million and a fair value of $(3) million.

During 2007 and the first six months of 2008, FirstEnergy entered into several forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with the anticipated issuance of variable-rate, short-term debt and fixed-rate, long-term debt securities by one or more of its subsidiaries as outstanding debt matures during 2008 and 2009. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury and LIBOR rates between the date of hedge inception and the date of the debt issuance. During the first six months of 2008, FirstEnergy terminated swaps with a notional value of $650 million and entered into swaps with a notional value of $850 million. FirstEnergy paid $14 million related to the terminations, $5 million of which was deemed ineffective and recognized in current period earnings. FirstEnergy will recognize the remaining loss over the life of the associated future debt. As of June 30, 2008, FirstEnergy had forward swaps with an aggregate notional amount of $600 million and a fair value of $6 million.

6.  ASSET RETIREMENT OBLIGATIONS

FirstEnergy has recognized applicable legal obligations under SFAS 143 for nuclear power plant decommissioning, reclamation of a sludge disposal pond and closure of two coal ash disposal sites. In addition, FirstEnergy has recognized conditional retirement obligations (primarily for asbestos remediation) in accordance with FIN 47.

The ARO of $1.3 billion as of June 30, 2008 is primarily related to the future nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. FirstEnergy utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.

FirstEnergy maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of June 30, 2008, the fair value of the decommissioning trust assets was approximately $2.0 billion.

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

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

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


7.  PENSION AND OTHER POSTRETIREMENT BENEFITS

FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its subsidiaries’ employees. The trusteed plans provide defined benefits based on years of service and compensation levels. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. FirstEnergy uses a December 31 measurement date for its pension and other postretirement benefit plans. The fair value of the plan assets represents the actual market value as of December 31, 2007. FirstEnergy also provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension benefits and other postretirement benefits from the time employees are hired until they become eligible to receive those benefits. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.

The components of FirstEnergy's net periodic pension cost and other postretirement benefit cost (including amounts capitalized) for the three months and six months ended June 30, 2008 and 2007, consisted of the following:

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



 
111

 


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

Pension and postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. FES and the Companies capitalize employee benefits related to construction projects. The net periodic pension costs and net periodic postretirement benefit costs (including amounts capitalized) recognized by FES and each of the Companies for the three months and six months ended June 30, 2008 and 2007 were as follows:

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

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

8.  VARIABLE INTEREST ENTITIES

FIN 46R addresses the consolidation of VIEs, including special-purpose entities, that are not controlled through voting interests or in which the equity investors do not bear the entity's residual economic risks and rewards. FirstEnergy and its subsidiaries consolidate VIEs when they are determined to be the VIE's primary beneficiary as defined by FIN 46R.

Trusts

FirstEnergy’s consolidated financial statements include PNBV and Shippingport, VIEs created in 1996 and 1997, respectively, to refinance debt originally issued in connection with sale and leaseback transactions. PNBV and Shippingport financial data are included in the consolidated financial statements of OE and CEI, respectively.

PNBV was established to purchase a portion of the lease obligation bonds issued in connection with OE’s 1987 sale and leaseback of its interests in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV. Ownership of PNBV includes a 3% equity interest by an unaffiliated third party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary of OE. Shippingport was established to purchase all of the lease obligation bonds issued in connection with CEI’s and TE’s Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE used debt and available funds to purchase the notes issued by Shippingport.

 
112

 


Loss Contingencies

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

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

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

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

Power Purchase Agreements

In accordance with FIN 46R, FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to the Companies and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec, maintains approximately 30 long-term power purchase agreements with NUG entities. The agreements were entered into pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.

FirstEnergy has determined that for all but eight of these entities, neither JCP&L, Met-Ed nor Penelec have variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of FIN 46R. JCP&L, Met-Ed or Penelec may hold variable interests in the remaining eight entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants. As required by FIN 46R, FirstEnergy periodically requests from these eight entities the information necessary to determine whether they are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. FirstEnergy has been unable to obtain the requested information, which in most cases was deemed by the requested entity to be proprietary. As such, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R.

Since FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs it may incur for power. FirstEnergy expects any above-market costs it incurs to be recovered from customers. Purchased power costs from these entities during the three months and six months ended June 30, 2008 and 2007 are shown in the following table:

 
113

 



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

Transition Bonds

The consolidated financial statements of FirstEnergy and JCP&L include the results of JCP&L Transition Funding and JCP&L Transition Funding II, wholly owned limited liability companies of JCP&L. In June 2002, JCP&L Transition Funding sold $320 million of transition bonds to securitize the recovery of JCP&L's bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. In August 2006, JCP&L Transition Funding II sold $182 million of transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS.

JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. As of June 30, 2008, $385 million of the transition bonds were outstanding. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consists primarily of bondable transition property.

Bondable transition property represents the irrevocable right under New Jersey law of a utility company to charge, collect and receive from its customers, through a non-bypassable TBC, the principal amount and interest on transition bonds and other fees and expenses associated with their issuance. JCP&L sold its bondable transition property to JCP&L Transition Funding and JCP&L Transition Funding II and, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to separate servicing agreements with JCP&L Transition Funding and JCP&L Transition Funding II. For the two series of transition bonds, JCP&L is entitled to aggregate quarterly servicing fees of $157,000 payable from TBC collections.

9.  INCOME TAXES

On January 1, 2007, FirstEnergy adopted FIN 48, which provides guidance for accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109. This interpretation prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken on a company’s tax return. FIN 48 also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and transition. The evaluation of a tax position in accordance with this interpretation is a two-step process. The first step is to determine if it is more likely than not that a tax position will be sustained upon examination, based on the merits of the position, and should therefore be recognized. The second step is to measure a tax position that meets the more likely than not recognition threshold to determine the amount of income tax benefit to recognize in the financial statements.

As of January 1, 2007, the total amount of FirstEnergy’s unrecognized tax benefits was $268 million. FirstEnergy recorded a $2.7 million cumulative effect adjustment to the January 1, 2007 balance of retained earnings to increase reserves for uncertain tax positions. Of the total amount of unrecognized income tax benefits, $92 million would favorably affect FirstEnergy’s effective tax rate, if recognized in 2008. The majority of items that would not affect the 2008 effective tax rate would be purchase accounting adjustments to goodwill, if recognized in 2008. During the first six months of 2008 and 2007, there were no material changes to FirstEnergy’s unrecognized tax benefits. As of June 30, 2008, FirstEnergy expects that it is reasonably possible that approximately $155 million of the unrecognized benefits may be resolved within the next twelve months, of which $54 million to $134 million, if recognized, would affect FirstEnergy’s effective tax rate.  The potential decrease in the amount of unrecognized tax benefits is primarily associated with issues related to the capitalization of certain costs, capital gains and losses recognized on the disposition of assets and various other tax items.

FIN 48 also requires companies to recognize interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes, consistent with its policy prior to implementing FIN 48. The net amount of interest accrued as of June 30, 2008 was $60 million, as compared to $53 million as of December 31, 2007.

 
114

 

FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state tax authorities. All state jurisdictions are open from 2001-2007. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items are under appeal. The federal audits for the years 2004-2006 are expected to close before December 2008, but management anticipates certain items to be appealed. The IRS began auditing the year 2007 in February 2007 and the year 2008 in February 2008 under its Compliance Assurance Process experimental program. Neither audit is expected to close before December 2008. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy’s financial condition or results of operations.

10.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

(A)   GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As of June 30, 2008, outstanding guarantees and other assurances aggregated approximately $4.3 billion, consisting of parental guarantees - $0.9 billion, subsidiaries’ guarantees - $2.7 billion, surety bonds - $0.1 billion and LOCs - $0.6 billion.

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.4 billion (included in the $0.9 billion discussed above) as of June 30, 2008 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event,” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. As of June 30, 2008, FirstEnergy's maximum exposure under these collateral provisions was $542 million.

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $74 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

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

(B)  
ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergy with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FirstEnergy estimates capital expenditures for environmental compliance of approximately $1.4 billion for the period 2008-2012.

FirstEnergy accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in FirstEnergy’s determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.

Clean Air Act Compliance

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

 
115

 

The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the CAA. FirstEnergy has disputed those alleged violations based on its CAA permit, the Ohio SIP and other information provided to the EPA at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding emission limits applicable to the common stack for Bay Shore Units 2, 3 and 4.

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

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

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

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

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

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

 
116

 

National Ambient Air Quality Standards

In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR would have required reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2), ultimately capping SO2 emissions in affected states to just 2.5 million tons annually and NOX emissions to just 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” The court ruling also vacated the CAIR regional cap and trade programs for SO2 and NOX, which is currently not expected to, but may, materially impair the value of emissions allowances obtained for future compliance. The future cost of compliance with these regulations may be substantial and will depend on the action taken by the EPA or Congress in response to the Court’s ruling.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the court vacated the CAMR ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA petitioned for rehearing by the entire court, which denied the petition on May 20, 2008.  The EPA must now petition for United States Supreme Court review of that ruling or take regulatory action to promulgate new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with mercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately implemented.

Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant, FirstEnergy’s only Pennsylvania coal-fired power plant, until 2015, if at all.

W. H. Sammis Plant

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

On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergy could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree are currently estimated to be $1.3 billion for 2008-2012 ($650 million of which is expected to be spent during 2008, with the largest portion of the remaining $650 million expected to be spent in 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 2012. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. Also, in an April 16, 2008 speech, President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition, the EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

 
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There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level.  At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the Senate Environmental and Public Works Committees have passed one such bill. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. On July 11, 2008, the EPA released an Advance Notice of Proposed Rulemaking, soliciting input from the public on the effects of climate change and the potential ramifications of regulation of CO2 under the CAA.

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

Clean Water Act

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

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

Regulation of Hazardous Waste

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

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities.  As of June 30, 2008, FirstEnergy had approximately $2.0 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seeks for these facilities.

 
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The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site may be liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of June 30, 2008, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $95 million (JCP&L - $68 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through June 30, 2008. Included in the total for JCP&L are accrued liabilities of approximately $57 million for environmental remediation of former manufactured gas plants in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

(C)   OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation

In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four of New Jersey’s electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory.

In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007.  Proceedings are continuing in the Superior Court and a case management conference with the presiding Judge was held on June 13, 2008.  At that conference, the plaintiffs stated their intent to drop their efforts to create a class-wide damage model and, instead of dismissing the class action, expressed their desire for a bifurcated trial on liability and damages.  The judge directed the plaintiffs to indicate, on or before August 22, 2008, how they intend to proceed under this scenario.  Thereafter, the judge expects to hold another pretrial conference to address plaintiffs' proposed procedure. FirstEnergy is defending this action but is unable to predict the outcome of this matter.  No liability has been accrued as of June 30, 2008.

Nuclear Plant Matters

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

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

Other Legal Matters

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

On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members. On April 5, 2007, the Court rejected the plaintiffs’ request to certify this case as a class action and, accordingly, did not appoint the plaintiffs as class representatives or their counsel as class counsel. On July 30, 2007, plaintiffs’ counsel voluntarily withdrew their request for reconsideration of the April 5, 2007 Court order denying class certification and the Court heard oral argument on the plaintiffs’ motion to amend their complaint, which OE opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend their complaint. The plaintiffs have appealed the Court’s denial of the motion for certification as a class action and motion to amend their complaint.

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

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

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

FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

 
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11.  REGULATORY MATTERS

(A)   RELIABILITY INITIATIVES

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

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

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

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

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

(B)   OHIO

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(C)   PENNSYLVANIA

Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. The fixed price under the agreement is expected to remain below wholesale market prices during the term of the agreement. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for their fixed income securities. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC.

Met-Ed and Penelec made a comprehensive transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of merger savings, with the comprehensive transition rate filing case.

The PPUC entered its opinion and order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes to NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission costs. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million).

 
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On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. From June through October 2007, initial responsive and reply briefs were filed by various parties. Oral arguments are scheduled to take place in September 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the results of operations of Met-Ed, Penelec and FirstEnergy.

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

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

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

(D)   NEW JERSEY

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of June 30, 2008, the accumulated deferred cost balance totaled approximately $293 million.

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

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

New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated through the creation of a number of working groups to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. In addition, public stakeholder meetings were held in 2006, 2007 and the first half of 2008.

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

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

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

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

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

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

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

(E)    FERC MATTERS

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or “SECA”) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC by year-end 2008.  In the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order.

 
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PJM Transmission Rate Design

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

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

Post Transition Period Rate Design

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

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

 
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Distribution of MISO Network Service Revenues

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

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

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

MISO Ancillary Services Market and Balancing Area Consolidation

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

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

Interconnection Agreement with AMP-Ohio

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

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

Duquesne’s Request to Withdraw from PJM

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

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

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

Complaint against PJM RPM Auction

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

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

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

MISO Resource Adequacy Proposal

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

Organized Wholesale Power Markets

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

SFAS 141(R) – “Business Combinations”

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

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

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

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

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

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

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

13.  SEGMENT INFORMATION

FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio transitional generation services. The “Other” segment primarily consists of telecommunications services. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable operating segments.”

The energy delivery services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems and is responsible for the regulated generation commodity operations of FirstEnergy’s Pennsylvania and New Jersey electric utility subsidiaries. Its revenues are primarily derived from the delivery of electricity, cost recovery of regulatory assets and default service electric generation sales to non-shopping customers in its Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES under partial requirements purchased power agreements and from non-affiliated power suppliers as well as the net PJM transmission expenses related to the delivery of that generation load.

The competitive energy services segment supplies electric power to its electric utility affiliates, provides competitive electricity sales primarily in Ohio, Pennsylvania, Maryland and Michigan, owns or leases and operates FirstEnergy’s generating facilities and purchases electricity to meet its sales obligations. The segment's net income is primarily derived from the affiliated company PSA sales and the non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO to deliver electricity to the segment’s customers. The segment’s internal revenues represent the affiliated company PSA sales.

The Ohio transitional generation services segment represents the regulated generation commodity operations of FirstEnergy’s Ohio electric utility subsidiaries. Its revenues are primarily derived from electric generation sales to non-shopping customers under the PLR obligations of the Ohio Companies. Its results reflect the purchase of electricity from the competitive energy services segment through full-requirements PSA arrangements, the deferral and amortization of certain fuel costs authorized for recovery by the energy delivery services segment and the net MISO transmission revenues and expenses related to the delivery of generation load. This segment’s total assets consist of accounts receivable for generation revenues from retail customers.

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

 
131

 


  14. SUPPLEMENTAL GUARANTOR INFORMATION

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

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

 
132

 

 

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

 
 
133

 
 

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

 
 
134

 

 

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

 
135

 



FIRSTENERGY SOLUTIONS CORP.
                               
CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
                               
For the Six Months Ended June 30, 2007
 
FES
   
FGCO
   
NGC
   
Eliminations
   
Consolidated
 
   
(In thousands)
 
                               
REVENUES
  $ 2,094,245     $ 1,004,908     $ 513,183     $ (1,525,312 )   $ 2,087,024  
                                         
EXPENSES:
                                       
Fuel
    9,880       436,884       55,651       -       502,415  
Purchased power from non-affiliates
    349,076       -       -       -       349,076  
Purchased power from affiliates
    1,515,432       118,727       38,221       (1,525,312 )     147,068  
Other operating expenses
    81,768       164,789       250,184       -       496,741  
Provision for depreciation
    922       50,175       45,433       -       96,530  
General taxes
    10,536       19,618       12,474       -       42,628  
Total expenses
    1,967,614       790,193       401,963       (1,525,312 )     1,634,458  
                                         
OPERATING INCOME
    126,631       214,715       111,220       -       452,566  
                                         
OTHER INCOME (EXPENSE):
                                       
Miscellaneous income, including
                                       
net income from equity investees
    188,729       294       9,415       (163,337 )     35,101  
Interest expense - affiliates
    -       (42,321 )     (9,942 )     -       (52,263 )
Interest expense - other
    (7,158 )     (12,876 )     (19,017 )     -       (39,051 )
Capitalized interest
    11       5,155       2,466       -       7,632  
Total other income (expense)
    181,582       (49,748 )     (17,078 )     (163,337 )     (48,581 )
                                         
INCOME BEFORE INCOME TAXES
    308,213       164,967       94,142       (163,337 )     403,985  
                                         
INCOME TAXES
    54,293       62,181       33,591       -       150,065  
                                         
NET INCOME
  $ 253,920     $ 102,786     $ 60,551     $ (163,337 )   $ 253,920  
 
 
 
 
136

 
 

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

 
137

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

 
138

 
 

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

 
139

 



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

 
140


 
ITEM 3.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk Information” in Item 2 above.

ITEM 4.   CONTROLS AND PROCEDURES

(a)   EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES – FIRSTENERGY

FirstEnergy’s chief executive officer and chief financial officer have reviewed and evaluated the registrant's disclosure controls and procedures. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, those officers have concluded that the registrant's disclosure controls and procedures are effective and were designed to bring to their attention material information relating to the registrant and its consolidated subsidiaries by others within those entities.

(b)   CHANGES IN INTERNAL CONTROLS

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

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

(a)   EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Each registrant's chief executive officer and chief financial officer have reviewed and evaluated such registrant's disclosure controls and procedures. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, those officers have concluded that such registrant's disclosure controls and procedures are effective and were designed to bring to their attention material information relating to such registrant and its consolidated subsidiaries by others within those entities.

(b)   CHANGES IN INTERNAL CONTROLS

During the quarter ended June 30, 2008, there were no changes in the registrants' internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting.



 
141

 

PART II. OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

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

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

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

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

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

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

(c)   FirstEnergy

The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock.
 
   
Period
 
   
April 1-30,
 
May 1-31,
 
June 1-30,
 
Second
 
   
2008
 
2008
 
2008
 
Quarter
 
Total Number of Shares Purchased (a)
 
237,587
 
207,833
 
556,691
 
1,002,111
 
Average Price Paid per Share
 
$74.46
 
$77.77
 
$80.22
 
$78.35
 
Total Number of Shares Purchased
                 
As Part of Publicly Announced Plans
                 
or Programs (b)
 
-
 
-
 
-
 
-
 
Maximum Number (or Approximate Dollar
                 
Value) of Shares that May Yet Be
                 
Purchased Under the Plans or Programs
 
-
 
-
 
-
 
-
 

(a)
Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock under its 2007 Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the 2007 Incentive Compensation Plan and the Executive Deferred Compensation Plan, and shares purchased as part of publicly announced plans.
   
(b)
On December 10, 2007, FirstEnergy’s plan to repurchase up to 16 million shares of its common stock through June 30, 2008, was concluded.

 
 
142

 


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

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

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

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


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

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


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

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

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


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

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


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

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

Based on this result, the Board of Directors will further review this proposal.
 
 
 
143

 

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

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

Based on this result, the Board of Directors will further review this proposal.
 
ITEM 5.   OTHER INFORMATION

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

The description of the potential payments set forth above does not purport to be complete and is qualified in its entirety by reference to the Form of Special Severance Agreements which was filed as Exhibit 10.1 to FirstEnergy’s Form 10-K for the year ended December 31, 2007 and is incorporated herein by reference as part of this item.
 
ITEM 6.   EXHIBITS
    
Exhibit
Number
     
     
         
FirstEnergy
     
 
   12
Fixed charge ratios
   
 
   15
Letter from independent registered public accounting firm
   
 
   31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
   
 
   31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
   
 
   32
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
   
FES
   
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 
 
32
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
 
OE
   
 
12
Fixed charge ratios
 
 
15
Letter from independent registered public accounting firm
 
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 
 
32
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
 
CEI
   
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 
 
32
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
 
TE
   
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 
 
32
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
 
JCP&L
   
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 
 
32
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
 
Met-Ed
 
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 
32
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
 
 
144

 
 
Penelec
 
 
12
Fixed charge ratios
 
15
Letter from independent registered public accounting firm
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 
32
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350

Pursuant to reporting requirements of respective financings, FirstEnergy, OE and Penelec are required to file fixed charge ratios as an exhibit to this Form 10-Q.

Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but each hereby agrees to furnish to the SEC on request any such documents.

 
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SIGNATURES



Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


August 7, 2008





 
FIRSTENERGY CORP.
 
Registrant
   
 
FIRSTENERGY SOLUTIONS CORP.
 
Registrant
   
 
OHIO EDISON COMPANY
 
Registrant
   
 
THE CLEVELAND ELECTRIC
 
ILLUMINATING COMPANY
 
Registrant
   
 
THE TOLEDO EDISON COMPANY
 
Registrant
   
 
METROPOLITAN EDISON COMPANY
 
Registrant
   
 
PENNSYLVANIA ELECTRIC COMPANY
 
Registrant



 
/s/  Harvey L. Wagner
 
Harvey L. Wagner
 
Vice President, Controller
 
and Chief Accounting Officer



 
JERSEY CENTRAL POWER & LIGHT COMPANY
 
Registrant
   
   
   
 
/s/  Paulette R. Chatman
 
Paulette R. Chatman
 
Controller
 
(Principal Accounting Officer)
 
 

 
146