main_10q.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 September 30, 2009

OR

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

For the transition period from
 
to
 

Commission
Registrant; State of Incorporation;
I.R.S. Employer
File Number
Address; and Telephone Number
Identification No.
     
333-21011
FIRSTENERGY CORP.
34-1843785
 
(An Ohio Corporation)
 
 
76 South Main Street
 
 
Akron, OH  44308
 
 
Telephone (800)736-3402
 
     
000-53742
FIRSTENERGY SOLUTIONS CORP.
31-1560186
 
(An Ohio Corporation)
 
 
c/o FirstEnergy Corp.
 
 
76 South Main Street
 
 
Akron, OH 44308
 
 
Telephone (800)736-3402
 
     
1-2578
OHIO EDISON COMPANY
34-0437786
 
(An Ohio Corporation)
 
 
c/o FirstEnergy Corp.
 
 
76 South Main Street
 
 
Akron, OH  44308
 
 
Telephone (800)736-3402
 
     
1-2323
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
34-0150020
 
(An Ohio Corporation)
 
 
c/o FirstEnergy Corp.
 
 
76 South Main Street
 
 
Akron, OH  44308
 
 
Telephone (800)736-3402
 
     
1-3583
THE TOLEDO EDISON COMPANY
34-4375005
 
(An Ohio Corporation)
 
 
c/o FirstEnergy Corp.
 
 
76 South Main Street
 
 
Akron, OH  44308
 
 
Telephone (800)736-3402
 
     
1-3141
JERSEY CENTRAL POWER & LIGHT COMPANY
21-0485010
 
(A New Jersey Corporation)
 
 
c/o FirstEnergy Corp.
 
 
76 South Main Street
 
 
Akron, OH  44308
 
 
Telephone (800)736-3402
 
     
1-446
METROPOLITAN EDISON COMPANY
23-0870160
 
(A Pennsylvania Corporation)
 
 
c/o FirstEnergy Corp.
 
 
76 South Main Street
 
 
Akron, OH  44308
 
 
Telephone (800)736-3402
 
     
1-3522
PENNSYLVANIA ELECTRIC COMPANY
25-0718085
 
(A Pennsylvania Corporation)
 
 
c/o FirstEnergy Corp.
 
 
76 South Main Street
 
 
Akron, OH  44308
 
 
Telephone (800)736-3402
 

 
 

 


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

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

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

Yes (X) No (  )
FirstEnergy Corp.

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

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

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

Smaller Reporting
Company
(  )
N/A

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

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

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


 
OUTSTANDING
CLASS
AS OF Novembe 6, 2009
FirstEnergy Corp., $0.10 par value
304,835, 407
FirstEnergy Solutions Corp., no par value
7
Ohio Edison Company, no par value
60
The Cleveland Electric Illuminating Company, no par value
67,930,743
The Toledo Edison Company, $5 par value
29,402,054
Jersey Central Power & Light Company, $10 par value
13,628,447
Metropolitan Edison Company, no par value
859,500
Pennsylvania Electric Company, $20 par value
4,427,577

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


 
 

 


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

OMISSION OF CERTAIN INFORMATION

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

 
 

 

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

Actual results may differ materially due to:
·  
The speed and nature of increased competition in the electric utility industry and legislative and regulatory changes affecting how generation rates will be determined following the expiration of existing rate plans in Pennsylvania.
·  
The impact of the PUCO’s regulatory process on the Ohio Companies associated with the distribution rate case.
·  
Economic or weather conditions affecting future sales and margins.
·  
Changes in markets for energy services.
·  
Changing energy and commodity market prices and availability.
·  
Replacement power costs being higher than anticipated or inadequately hedged.
·  
The continued ability of FirstEnergy’s regulated utilities to collect transition and other charges.
·  
Operating and maintenance costs being higher than anticipated.
·  
Other legislative and regulatory changes, and revised environmental requirements, including possible GHG emission regulations.
·  
The potential impacts of the U.S. Court of Appeals’ July 11, 2008 decision requiring revisions to the CAIR rules and the scope of any laws, rules or regulations that may ultimately take their place.
·  
The uncertainty of the timing and amounts of the capital expenditures needed to, among other things, implement the Air Quality Compliance Plan (including that such amounts could be higher than anticipated or that certain generating units may need to be shut down) or levels of emission reductions related to the Consent Decree resolving the NSR litigation or other potential regulatory initiatives or actions.
·  
Adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or operating permits and oversight) by the NRC.
·  
Met-Ed’s and Penelec’s transmission service charge filings with the PPUC.
·  
The continuing availability of generating units and their ability to operate at or near full capacity.
·  
The ability to comply with applicable state and federal reliability standards.
·  
The ability to accomplish or realize anticipated benefits from strategic goals (including employee workforce initiatives).
·  
The ability to improve electric commodity margins and to experience growth in the distribution business.
·  
The changing market conditions that could affect the value of assets held in the registrants’ nuclear decommissioning trusts, pension trusts and other trust funds, and cause FirstEnergy to make additional contributions sooner, or in amounts that are larger than currently anticipated.
·  
The ability to access the public securities and other capital and credit markets in accordance with FirstEnergy’s financing plan and the cost of such capital.
·  
Changes in general economic conditions affecting the registrants.
·  
The state of the capital and credit markets affecting the registrants.
·  
Interest rates and any actions taken by credit rating agencies that could negatively affect the registrants’ access to financing or their costs and increase requirements to post additional collateral to support outstanding commodity positions, LOCs and other financial guarantees.
·  
The continuing decline of the national and regional economy and its impact on the registrants’ major industrial and commercial customers.
·  
Issues concerning the soundness of financial institutions and counterparties with which the registrants do business.
·  
The risks and other factors discussed from time to time in the registrants’ SEC filings, and other similar factors.

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


 
 

 

TABLE OF CONTENTS



   
Pages
 
     
Glossary of Terms
iii-iv
 
       
Item 1.    Financial Statements
   
       
FirstEnergy Corp.
   
       
 
Consolidated Statements of Income
1
 
 
Consolidated Statements of Comprehensive Income (Loss)
2
 
 
Consolidated Balance Sheets
3
 
 
Consolidated Statements of Cash Flows
4
 
       
FirstEnergy Solutions Corp.
   
       
 
Consolidated Statements of Income and Comprehensive Income
5
 
 
Consolidated Balance Sheets
6
 
 
Consolidated Statements of Cash Flows
7
 
       
Ohio Edison Company
   
       
 
Consolidated Statements of Income and Comprehensive Income (Loss)
8
 
 
Consolidated Balance Sheets
9
 
 
Consolidated Statements of Cash Flows
10
 
       
The Cleveland Electric Illuminating Company
   
       
 
Consolidated Statements of Income and Comprehensive Income (Loss)
11
 
 
Consolidated Balance Sheets
12
 
 
Consolidated Statements of Cash Flows
13
 
       
The Toledo Edison Company
   
       
 
Consolidated Statements of Income and Comprehensive Income (Loss)
14
 
 
Consolidated Balance Sheets
15
 
 
Consolidated Statements of Cash Flows
16
 
       
Jersey Central Power & Light Company
   
       
 
Consolidated Statements of Income and Comprehensive Income
17
 
 
Consolidated Balance Sheets
18
 
 
Consolidated Statements of Cash Flows
19
 
       
Metropolitan Edison Company
   
       
 
Consolidated Statements of Income and Comprehensive Income (Loss)
20
 
 
Consolidated Balance Sheets
21
 
 
Consolidated Statements of Cash Flows
22
 
       
 
Pennsylvania Electric Company
   
       
 
Consolidated Statements of Income and Comprehensive Income (Loss)
23
 
  Consolidated Balance Sheets
24
 
 
Consolidated Statements of Cash Flows
25
 

 
i

 

TABLE OF CONTENTS (Cont'd)


   
Pages
     
Combined Notes To Consolidated Financial Statements
26-65
   
Report of Independent Registered Public Accounting Firm
 
   
FirstEnergy Corp.
66
FirstEnergy Solutions Corp.
67
Ohio Edison  Company
68
The Cleveland Electric Illuminating Company
69
The Toledo Edison Company
70
Jersey Central Power & Light Company
71
Metropolitan Edison Company
72
Pennsylvania Electric Company
73
   
Item 2.   Management's Discussion and Analysis of Registrant and Subsidiaries
74-118
   
Management's Narrative Analysis of Results of Operations
 
   
FirstEnergy Solutions Corp.
119-121
Ohio Edison Company
122-123
The Cleveland Electric Illuminating Company
124-125
The Toledo Edison Company
126-127
Jersey Central Power & Light Company
128-129
Metropolitan Edison Company
130-131
Pennsylvania Electric Company
132-133
   
Item 3.    Quantitative and Qualitative Disclosures About Market Risk
134
     
Item 4.    Controls and Procedures – FirstEnergy
134
   
Item 4T.  Controls and Procedures – FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec
134
   
Part II.     Other Information
 
     
Item 1.    Legal Proceedings
135
     
Item 1A. Risk Factors
135
   
Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds
135
   
        Item 5.    Other Information     135
   
Item 6.    Exhibits
136-137



 
ii

 

GLOSSARY OF TERMS

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

ATSI
American Transmission Systems, Incorporated, owns and operates transmission facilities
CEI
The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
FENOC
FirstEnergy Nuclear Operating Company, operates nuclear generating facilities
FES
FirstEnergy Solutions Corp., provides energy-related products and services
FESC
FirstEnergy Service Company, provides legal, financial and other corporate support services
FEV
FirstEnergy Ventures Corp., invests in certain unregulated enterprises and business ventures
FGCO
FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities
FirstEnergy
FirstEnergy Corp., a public utility holding company
GPU
GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on
November 7, 2001
JCP&L
Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
JCP&L Transition
   Funding
JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition bonds
JCP&L Transition
   Funding II
JCP&L Transition Funding II LLC, a Delaware limited liability company and issuer of transition bonds
Met-Ed
Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
NGC
FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities
OE
Ohio Edison Company, an Ohio electric utility operating subsidiary
Ohio Companies
CEI, OE and TE
Penelec
Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Penn
Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
Pennsylvania Companies
Met-Ed, Penelec and Penn
PNBV
PNBV Capital Trust, a special purpose entity created by OE in 1996
Shelf Registrants
OE, CEI, TE, JCP&L, Met-Ed and Penelec
Shippingport
Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
Signal Peak
A joint venture between FirstEnergy Ventures Corp. and Boich Companies, that owns mining and
   coal transportation operations near Roundup, Montana
TE
The Toledo Edison Company, an Ohio electric utility operating subsidiary
Utilities
OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec
Waverly
The Waverly Power and Light Company, a wholly owned subsidiary of Penelec
   
The following abbreviations and acronyms are used to identify frequently used terms in this report:
   
AEP
American Electric Power Company, Inc.
ALJ
Administrative Law Judge
AMP-Ohio
American Municipal Power-Ohio, Inc.
AOCL
Accumulated Other Comprehensive Loss
AQC
Air Quality Control
BGS
Basic Generation Service
CAA
Clean Air Act
CAIR
Clean Air Interstate Rule
CAMR
Clean Air Mercury Rule
CBP
Competitive Bid Process
CO2
Carbon Dioxide
CTC
Competitive Transition Charge
DOJ
United States Department of Justice
DPA
Department of the Public Advocate, Division of Rate Counsel (New Jersey)
EE&C
Energy Efficiency and Conservation
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
FMB
First Mortgage Bond
GAAP
Accounting Principles Generally Accepted in the United States
GHG
Greenhouse Gases

 
iii

 

GLOSSARY OF TERMS, Cont'd.

IRS
Internal Revenue Service
kV
Kilovolt
KWH
Kilowatt-hours
LED
Light-emitting Diode
LIBOR
London Interbank Offered Rate
LOC
Letter of Credit
MISO
Midwest Independent Transmission System Operator, Inc.
Moody's
Moody's Investors Service, Inc.
MRO
Market Rate Offer
MW
Megawatts
MWH
Megawatt-hours
NAAQS
National Ambient Air Quality Standards
NERC
North American Electric Reliability Corporation
NJBPU
New Jersey Board of Public Utilities
NOV
Notice of Violation
NOX
Nitrogen Oxide
NRC
Nuclear Regulatory Commission
NSR
New Source Review
NUG
Non-Utility Generation
NUGC
Non-Utility Generation Charge
NYMEX
New York Mercantile Exchange
OCI
Other Comprehensive Income
OPEB
Other Post-Employment Benefits
OVEC
Ohio Valley Electric Corporation
PCRB
Pollution Control Revenue Bond
PJM
PJM Interconnection L. L. C.
PLR
Provider of Last Resort; an electric utility's obligation to provide generation service to customers
   whose alternative supplier fails to deliver service
PPUC
Pennsylvania Public Utility Commission
PSA
Power Supply Agreement
PUCO
Public Utilities Commission of Ohio
QSPE
Qualifying Special-Purpose Entity
RCP
Rate Certainty Plan
RFP
Request for Proposal
RTC
Regulatory Transition Charge
RTO
Regional Transmission Organization
S&P
Standard & Poor's Ratings Service
SB221
Amended Substitute Senate Bill 221
SBC
Societal Benefits Charge
SEC
U.S. Securities and Exchange Commission
SECA
Seams Elimination Cost Adjustment
SIP
State Implementation Plan(s) Under the Clean Air Act
SNCR
Selective Non-Catalytic Reduction
SO2
Sulfur Dioxide
TBC
Transition Bond Charge
TMI-2
Three Mile Island Unit 2
TSC
Transmission Service Charge
VERO
Voluntary Enhanced Retirement Option
VIE
Variable Interest Entity

 
iv

 
 


FIRSTENERGY CORP.
 
                         
CONSOLIDATED STATEMENTS OF INCOME
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
September 30
   
September 30
 
   
2009
   
2008
   
2009
   
2008
 
   
(In millions, except per share amounts)
 
REVENUES:
                       
Electric utilities
  $ 2,940     $ 3,469     $ 8,751     $ 9,247  
Unregulated businesses
    468       435       1,262       1,179  
Total revenues *
    3,408       3,904       10,013       10,426  
                                 
EXPENSES:
                               
Fuel
    302       356       890       1,000  
Purchased power
    1,313       1,306       3,480       3,376  
Other operating expenses
    665       794       2,103       2,374  
Provision for depreciation
    188       168       550       500  
Amortization of regulatory assets
    261       291       903       795  
Deferral of regulatory assets
    -       (58 )     (136 )     (261 )
General taxes
    192       201       587       596  
Total expenses
    2,921       3,058       8,377       8,380  
                                 
OPERATING INCOME
    487       846       1,636       2,046  
                                 
OTHER INCOME (EXPENSE):
                               
Investment income
    191       40       207       73  
Interest expense
    (355 )     (192 )     (755 )     (559 )
Capitalized interest
    35       15       96       36  
Total other expense
    (129 )     (137 )     (452 )     (450 )
                                 
INCOME BEFORE INCOME TAXES
    358       709       1,184       1,596  
                                 
INCOME TAXES
    128       238       430       585  
                                 
NET INCOME
    230       471       754       1,011  
                                 
Noncontrolling interest income (loss)
    (4 )     -       (14 )     1  
                                 
EARNINGS AVAILABLE TO FIRSTENERGY CORP.
  $ 234     $ 471     $ 768     $ 1,010  
                                 
                                 
BASIC EARNINGS PER SHARE OF COMMON STOCK
  $ 0.77     $ 1.55     $ 2.52     $ 3.32  
                                 
                                 
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
    304       304       304       304  
                                 
                                 
DILUTED EARNINGS PER SHARE OF COMMON STOCK
  $ 0.77     $ 1.54     $ 2.51     $ 3.29  
                                 
                                 
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
    306       307       306       307  
                                 
                                 
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK
  $ 1.10     $ 1.10     $ 1.65     $ 1.65  
                                 
                                 
* Includes excise tax collections of $106 million and $115 million in the three months ended September 30, 2009 and 2008, respectively,
 
and $310 million and $329 million in the nine months ended September 2009 and 2008, respectively.
 
                                 
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.
 

 
1

 


FIRSTENERGY CORP.
 
                         
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
September 30
   
September 30
 
   
2009
   
2008
   
2009
   
2008
 
   
(In millions)
 
                         
NET INCOME
  $ 230     $ 471     $ 754     $ 1,011  
                                 
OTHER COMPREHENSIVE INCOME (LOSS):
                               
Pension and other postretirement benefits
    (480 )     (20 )     24       (60 )
Unrealized gain (loss) on derivative hedges
    19       26       57       21  
Change in unrealized gain on available-for-sale securities
    (108 )     (100 )     (76 )     (181 )
Other comprehensive income (loss)
    (569 )     (94 )     5       (220 )
Income tax expense (benefit) related to other comprehensive income
    (216 )     (34 )     26       (81 )
Other comprehensive income (loss), net of tax
    (353 )     (60 )     (21 )     (139 )
                                 
COMPREHENSIVE INCOME (LOSS)
    (123 )     411       733       872  
                                 
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE
                               
TO NONCONTROLLING INTEREST
    (4 )     -       (14 )     1  
                                 
COMPREHENSIVE INCOME (LOSS) AVAILABLE TO FIRSTENERGY CORP.
  $ (119 )   $ 411     $ 747     $ 871  
                                 
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
 
these statements.
                               

 
2

 

 
FIRSTENERGY CORP.
 
             
CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
   
September 30,
   
December 31,
 
    2009     2008  
   
(In millions)
 
ASSETS
           
             
CURRENT ASSETS:
           
Cash and cash equivalents
  $ 838     $ 545  
Receivables-
               
Customers (less accumulated provisions of $28 million for uncollectible accounts)
    1,260       1,304  
Other (less accumulated provisions of $9 million for uncollectible accounts)
    132       167  
Materials and supplies, at average cost
    621       605  
Prepaid taxes
    585       283  
Other
    334       149  
      3,770       3,053  
PROPERTY, PLANT AND EQUIPMENT:
               
In service
    27,526       26,482  
Less - Accumulated provision for depreciation
    11,267       10,821  
      16,259       15,661  
Construction work in progress
    2,490       2,062  
      18,749       17,723  
INVESTMENTS:
               
Nuclear plant decommissioning trusts
    1,856       1,708  
Investments in lease obligation bonds
    553       598  
Other
    698       711  
      3,107       3,017  
DEFERRED CHARGES AND OTHER ASSETS:
               
Goodwill
    5,575       5,575  
Regulatory assets
    2,543       3,140  
Power purchase contract asset
    220       434  
Other
    710       579  
      9,048       9,728  
    $ 34,674     $ 33,521  
LIABILITIES AND CAPITALIZATION
               
                 
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $ 2,020     $ 2,476  
Short-term borrowings
    1,653       2,397  
Accounts payable
    692       794  
Accrued taxes
    257       333  
Other
    1,114       1,098  
      5,736       7,098  
CAPITALIZATION:
               
Common stockholders’ equity-
               
Common stock, $0.10 par value, authorized 375,000,000 shares-
    31       31  
304,835,407 shares outstanding
               
Other paid-in capital
    5,438       5,473  
Accumulated other comprehensive loss
    (1,401 )     (1,380 )
Retained earnings
    4,424       4,159  
Total common stockholders' equity
    8,492       8,283  
Noncontrolling interest
    1       32  
Total equity
    8,493       8,315  
Long-term debt and other long-term obligations
    11,647       9,100  
      20,140       17,415  
NONCURRENT LIABILITIES:
               
Accumulated deferred income taxes
    2,562       2,163  
Asset retirement obligations
    1,401       1,335  
Deferred gain on sale and leaseback transaction
    1,001       1,027  
Power purchase contract liability
    685       766  
Retirement benefits
    1,500       1,884  
Lease market valuation liability
    274       308  
Other
    1,375       1,525  
      8,798       9,008  
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
               
    $ 34,674     $ 33,521  
                 
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
         

 
3

 
 

FIRSTENERGY CORP.
 
             
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
             
   
Nine Months Ended
 
   
September 30
 
   
2009
   
2008
 
   
(In millions)
 
             
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net income
  $ 754     $ 1,011  
Adjustments to reconcile net income to net cash from operating activities-
               
Provision for depreciation
    550       500  
Amortization of regulatory assets
    903       795  
Deferral of regulatory assets
    (136 )     (261 )
Nuclear fuel and lease amortization
    92       82  
Deferred purchased power and other costs
    (235 )     (138 )
Deferred income taxes and investment tax credits, net
    421       278  
Investment impairment
    39       63  
Deferred rents and lease market valuation liability
    (20 )     (62 )
Accrued compensation and retirement benefits
    20       (127 )
Stock-based compensation
    (1 )     (74 )
Gain on asset sales
    (12 )     (43 )
Electric service prepayment programs
    (10 )     (58 )
Cash collateral, net
    (85 )     21  
Gain on investment securities held in trusts
    (172 )     (43 )
Loss on debt redemption
    142       -  
Pension trust contribution
    (500 )     -  
Decrease (increase) in operating assets-
               
Receivables
    78       (117 )
Materials and supplies
    30       (34 )
Prepaid taxes
    (332 )     (259 )
Increase (decrease) in operating liabilities-
               
Accounts payable
    (103 )     (34 )
Accrued taxes
    (97 )     (166 )
Accrued interest
    121       107  
Other
    17       (10 )
Net cash provided from operating activities
    1,464       1,431  
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing-
               
Long-term debt
    4,151       631  
Short-term borrowings, net
    -       1,489  
Redemptions and Repayments-
               
Long-term debt
    (2,213 )     (733 )
Short-term borrowings, net
    (764 )     -  
Net controlled disbursement activity
    (15 )     6  
Common stock dividend payments
    (503 )     (503 )
Other
    (39 )     21  
Net cash provided from financing activities
    617       911  
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (1,575 )     (2,177 )
Proceeds from asset sales
    19       64  
Sales of investment securities held in trusts
    3,039       1,144  
Purchases of investment securities held in trusts
    (3,101 )     (1,215 )
Cash investments
    (4 )     72  
Restricted funds for debt redemption
    (150 )     (82 )
Other
    (16 )     (96 )
Net cash used for investing activities
    (1,788 )     (2,290 )
                 
Net change in cash and cash equivalents
    293       52  
Cash and cash equivalents at beginning of period
    545       129  
Cash and cash equivalents at end of period
  $ 838     $ 181  
                 
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral
 
part of these statements.
               

 
4

 

FIRSTENERGY SOLUTIONS CORP.
 
                         
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
September 30
   
September 30
 
   
2009
    2008    
2009
   
2008
 
   
(In thousands)
 
                         
REVENUES:
                       
Electric sales to affiliates
  $ 616,300     $ 785,681     $ 2,348,741     $ 2,266,271  
Electric sales to non-affiliates
    443,819       381,483       928,944       994,100  
Other
    44,453       74,440       394,145       151,627  
Total revenues
    1,104,572       1,241,604       3,671,830       3,411,998  
                                 
EXPENSES:
                               
Fuel
    294,693       349,946       871,160       982,185  
Purchased power from non-affiliates
    205,200       221,493       551,155       648,556  
Purchased power from affiliates
    35,290       15,821       149,746       75,834  
Other operating expenses
    305,935       279,184       891,555       863,468  
Provision for depreciation
    66,041       64,633       192,962       170,535  
General taxes
    21,700       21,736       66,361       64,728  
Total expenses
    928,859       952,813       2,722,939       2,805,306  
                                 
OPERATING INCOME
    175,713       288,791       948,891       606,692  
                                 
OTHER INCOME (EXPENSE):
                               
Investment income (loss)
    158,857       11,961       135,723       (6,332 )
Miscellaneous income
    2,804       6,466       12,840       19,781  
Interest expense to affiliates
    (2,209 )     (8,015 )     (8,503 )     (25,953 )
Interest expense - other
    (42,187 )     (32,769 )     (90,985 )     (81,809 )
Capitalized interest
    17,869       12,395       41,975       29,599  
Total other income (expense)
    135,134       (9,962 )     91,050       (64,714 )
                                 
INCOME BEFORE INCOME TAXES
    310,847       278,829       1,039,941       541,978  
                                 
INCOME TAXES
    111,164       93,174       372,175       198,245  
                                 
NET INCOME
    199,683       185,655       667,766       343,733  
                                 
OTHER COMPREHENSIVE INCOME (LOSS):
                               
Pension and other postretirement benefits
    (61,085 )     (1,821 )     13,604       (5,462 )
Unrealized gain on derivative hedges
    790       27,277       26,847       15,075  
Change in unrealized gain on available-for-sale securities
    (89,401 )     (90,198 )     (51,374 )     (159,759 )
Other comprehensive loss
    (149,696 )     (64,742 )     (10,923 )     (150,146 )
Income tax benefit related to other comprehensive loss
    (58,883 )     (24,781 )     (3,549 )     (55,497 )
Other comprehensive loss, net of tax
    (90,813 )     (39,961 )     (7,374 )     (94,649 )
                                 
TOTAL COMPREHENSIVE INCOME
  $ 108,870     $ 145,694     $ 660,392     $ 249,084  
                                 
The accompanying Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are an integral part of
 
these statements.
                               

 
5

 


FIRSTENERGY SOLUTIONS CORP.
 
             
CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
   
September 30,
   
December 31,
 
   
2009
   
2008
 
   
(In thousands)
 
ASSETS
           
CURRENT ASSETS:
           
Cash and cash equivalents
  $ 266,958     $ 39  
Receivables-
               
Customers (less accumulated provisions of $4,676,000 and $5,899,000,
               
respectively, for uncollectible accounts)
    155,489       86,123  
Associated companies
    344,387       378,100  
Other (less accumulated provisions of $6,702,000 and $6,815,000
               
respectively, for uncollectible accounts)
    47,579       24,626  
Notes receivable from associated companies
    428,016       129,175  
Materials and supplies, at average cost
    528,278       521,761  
Prepayments and other
    120,362       112,535  
      1,891,069       1,252,359  
PROPERTY, PLANT AND EQUIPMENT:
               
In service
    10,254,698       9,871,904  
Less - Accumulated provision for depreciation
    4,487,832       4,254,721  
      5,766,866       5,617,183  
Construction work in progress
    2,195,999       1,747,435  
      7,962,865       7,364,618  
INVESTMENTS:
               
Nuclear plant decommissioning trusts
    1,101,884       1,033,717  
Long-term notes receivable from associated companies
    8,817       62,900  
Other
    26,642       61,591  
      1,137,343       1,158,208  
DEFERRED CHARGES AND OTHER ASSETS:
               
Accumulated deferred income tax benefits
    38,099       267,762  
Lease assignment receivable from associated companies
    71,356       71,356  
Goodwill
    24,248       24,248  
Property taxes
    50,104       50,104  
Unamortized sale and leaseback costs
    58,350       69,932  
Other
    226,134       96,434  
      468,291       579,836  
    $ 11,459,568     $ 10,355,021  
LIABILITIES AND CAPITALIZATION
               
                 
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $ 1,631,766     $ 2,024,898  
Short-term borrowings-
               
Associated companies
    -       264,823  
Other
    100,000       1,000,000  
Accounts payable-
               
Associated companies
    387,182       472,338  
Other
    156,053       154,593  
Accrued taxes
    105,574       79,766  
Other
    227,788       248,439  
      2,608,363       4,244,857  
CAPITALIZATION:
               
Common stockholder's equity -
               
Common stock, without par value, authorized 750 shares,
               
7 shares outstanding
    1,466,697       1,464,229  
Accumulated other comprehensive loss
    (99,245 )     (91,871 )
Retained earnings
    2,239,831       1,572,065  
Total common stockholder's equity
    3,607,283       2,944,423  
Long-term debt and other long-term obligations
    2,640,092       571,448  
      6,247,375       3,515,871  
NONCURRENT LIABILITIES:
               
Deferred gain on sale and leaseback transaction
    1,001,298       1,026,584  
Accumulated deferred investment tax credits
    59,479       62,728  
Asset retirement obligations
    906,199       863,085  
Retirement benefits
    200,097       194,177  
Property taxes
    50,104       50,104  
Lease market valuation liability
    273,624       307,705  
Other
    113,029       89,910  
      2,603,830       2,594,293  
COMMITMENTS AND CONTINGENCIES (Note 9)
               
    $ 11,459,568     $ 10,355,021  
                 
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an integral part
 
of these statements.
               

 
6

 


FIRSTENERGY SOLUTIONS CORP.
 
             
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
             
   
Nine Months Ended
 
   
September 30
 
   
2009
   
2008
 
   
(In thousands)
 
             
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net income
  $ 667,766     $ 343,733  
Adjustments to reconcile net income to net cash from operating activities-
         
Provision for depreciation
    192,962       170,535  
Nuclear fuel and lease amortization
    94,244       81,950  
Deferred rents and lease market valuation liability
    (40,143 )     (36,702 )
Deferred income taxes and investment tax credits, net
    268,812       91,082  
Investment impairment
    36,169       58,173  
Accrued compensation and retirement benefits
    5,860       (2,110 )
Commodity derivative transactions, net
    25,794       3,634  
Gain on asset sales
    (9,832 )     (11,319 )
Gain on investment securities held in trusts
    (154,723 )     (34,032 )
Cash collateral, net
    (92,618 )     (8,827 )
Decrease (increase) in operating assets:
               
Receivables
    (55,774 )     106,574  
Materials and supplies
    38,543       (35,498 )
Prepayments and other current assets
    (35,315 )     (10,762 )
Increase (decrease) in operating liabilities:
               
Accounts payable
    (72,181 )     (61,035 )
Accrued taxes
    23,846       (90,767 )
Accrued interest
    31,770       15,420  
Other
    (43,369 )     (25,916 )
Net cash provided from operating activities
    881,811       554,133  
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing-
               
Long-term debt
    2,356,762       537,375  
Equity contribution from parent
    -       280,000  
Short-term borrowings, net
    -       747,686  
Redemptions and Repayments-
               
Long-term debt
    (618,213 )     (460,902 )
Short-term borrowings, net
    (1,164,823 )     -  
Common stock dividend payments
    -       (43,000 )
Other
    (20,006 )     -  
Net cash provided from financing activities
    553,720       1,061,159  
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (842,600 )     (1,417,205 )
Proceeds from asset sales
    16,129       15,218  
Sales of investment securities held in trusts
    2,152,717       596,291  
Purchases of investment securities held in trusts
    (2,175,135 )     (624,899 )
Loans to associated companies, net
    (298,841 )     (64,142 )
Restricted funds for debt redemption
    -       (81,640 )
Other
    (20,882 )     (38,915 )
Net cash used for investing activities
    (1,168,612 )     (1,615,292 )
                 
Net change in cash and cash equivalents
    266,919       -  
Cash and cash equivalents at beginning of period
    39       2  
Cash and cash equivalents at end of period
  $ 266,958     $ 2  
                 
The accompanying Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are an
 
 integral part of these balance sheets.
               

 
7

 


OHIO EDISON COMPANY
 
                         
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (LOSS)
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
September 30
   
September 30
 
                         
    2009    
2008
   
2009
   
2008
 
   
(In thousands)
 
STATEMENTS OF INCOME
                       
                         
REVENUES:
                       
Electric sales
  $ 575,377     $ 671,761     $ 1,942,612     $ 1,877,300  
Excise and gross receipts tax collections
    27,127       30,500       81,055       87,165  
Total revenues
    602,504       702,261       2,023,667       1,964,465  
                                 
EXPENSES:
                               
Purchased power from affiliates
    200,506       313,912       847,712       913,647  
Purchased power from non-affiliates
    161,732       35,462       397,875       83,962  
Other operating costs
    102,463       146,048       372,231       423,993  
Provision for depreciation
    22,407       14,997       65,916       57,904  
Amortization of regulatory assets, net
    17,404       42,582       59,910       87,664  
General taxes
    45,164       49,255       138,187       144,097  
Total expenses
    549,676       602,256       1,881,831       1,711,267  
                                 
OPERATING INCOME
    52,828       100,005       141,836       253,198  
                                 
OTHER INCOME (EXPENSE):
                               
Investment income
    20,285       19,323       39,796       45,866  
Miscellaneous income (expense)
    237       (938 )     2,108       (4,716 )
Interest expense
    (22,961 )     (17,309 )     (67,717 )     (51,851 )
Capitalized interest
    231       55       730       324  
Total other income (expense)
    (2,208 )     1,131       (25,083 )     (10,377 )
                                 
INCOME BEFORE INCOME TAXES
    50,620       101,136       116,753       242,821  
                                 
INCOME TAXES
    15,885       28,501       36,742       77,122  
                                 
NET INCOME
    34,735       72,635       80,011       165,699  
                                 
Noncontrolling interest income
    140       151       429       464  
                                 
EARNINGS AVAILABLE TO PARENT
  $ 34,595     $ 72,484     $ 79,582     $ 165,235  
                                 
STATEMENTS OF COMPREHENSIVE INCOME
                               
                                 
NET INCOME
  $ 34,735     $ 72,635     $ 80,011     $ 165,699  
                                 
OTHER COMPREHENSIVE INCOME (LOSS):
                               
Pension and other postretirement benefits
    (49,043 )     (3,994 )     46,559       (11,982 )
Change in unrealized gain on available-for-sale securities
    (7,695 )     (9,936 )     (9,676 )     (20,310 )
Other comprehensive income (loss)
    (56,738 )     (13,930 )     36,883       (32,292 )
Income tax expense (benefit) related to other comprehensive income
    (21,924 )     (5,105 )     15,915       (11,931 )
Other comprehensive income (loss), net of tax
    (34,814 )     (8,825 )     20,968       (20,361 )
                                 
COMPREHENSIVE INCOME (LOSS)
    (79 )     63,810       100,979       145,338  
                                 
COMPREHENSIVE INCOME ATTRIBUTABLE
                               
TO NONCONTROLLING INTEREST
    140       151       429       464  
                                 
COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT
  $ (219 )   $ 63,659     $ 100,550     $ 144,874  
                                 
The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part
         
of these statements.
                               
 

 
8

 


OHIO EDISON COMPANY
 
             
CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
   
September 30,
   
December 31,
 
   
2009
   
2008
 
      (In thousands)  
ASSETS
           
CURRENT ASSETS:
           
Cash and cash equivalents
  $ 329,745     $ 146,343  
Receivables-
               
Customers (less accumulated provisions of $6,113,000 and $6,065,000, respectively,
         
for uncollectible accounts)
    217,775       277,377  
Associated companies
    163,407       234,960  
Other (less accumulated provisions of $17,000 and $7,000, respectively,
               
for uncollectible accounts)
    16,862       14,492  
Notes receivable from associated companies
    89,410       222,861  
Prepayments and other
    15,394       5,452  
      832,593       901,485  
UTILITY PLANT:
               
In service
    2,993,708       2,903,290  
Less - Accumulated provision for depreciation
    1,148,804       1,113,357  
      1,844,904       1,789,933  
Construction work in progress
    32,292       37,766  
      1,877,196       1,827,699  
OTHER PROPERTY AND INVESTMENTS:
               
Long-term notes receivable from associated companies
    192,550       256,974  
Investment in lease obligation bonds
    230,025       239,625  
Nuclear plant decommissioning trusts
    121,638       116,682  
Other
    97,949       100,792  
      642,162       714,073  
DEFERRED CHARGES AND OTHER ASSETS:
               
Regulatory assets
    493,955       575,076  
Pension assets
    17,336       -  
Property taxes
    60,542       60,542  
Unamortized sale and leaseback costs
    36,378       40,130  
Other
    33,695       33,710  
      641,906       709,458  
    $ 3,993,857     $ 4,152,715  
LIABILITIES AND CAPITALIZATION
               
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $ 2,719     $ 101,354  
Short-term borrowings-
               
Associated companies
    75,002       -  
Other
    1,052       1,540  
Accounts payable-
               
Associated companies
    61,507       131,725  
Other
    36,503       26,410  
Accrued taxes
    73,666       77,592  
Accrued interest
    25,614       25,673  
Other
    127,056       85,209  
      403,119       449,503  
CAPITALIZATION:
               
Common stockholder's equity-
               
Common stock, without par value, authorized 175,000,000 shares -
               
60 shares outstanding
    1,228,463       1,224,416  
Accumulated other comprehensive loss
    (163,417 )     (184,385 )
Retained earnings
    183,605       254,023  
Total common stockholder's equity
    1,248,651       1,294,054  
Noncontrolling interest
    6,975       7,106  
Total equity
    1,255,626       1,301,160  
Long-term debt and other long-term obligations
    1,161,237       1,122,247  
      2,416,863       2,423,407  
NONCURRENT LIABILITIES:
               
Accumulated deferred income taxes
    699,399       653,475  
Accumulated deferred investment tax credits
    11,969       13,065  
Asset retirement obligations
    84,600       80,647  
Retirement benefits
    179,549       308,450  
Other
    198,358       224,168  
      1,173,875       1,279,805  
COMMITMENTS AND CONTINGENCIES (Note 9)
               
    $ 3,993,857     $ 4,152,715  
                 
The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of
 
these balance sheets.
               
 

 
9

 
 

OHIO EDISON COMPANY
 
             
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
             
   
Nine Months Ended
 
   
September 30
 
   
2009
   
2008
 
   
(In thousands)
 
             
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net income
  $ 80,011     $ 165,699  
Adjustments to reconcile net income to net cash from operating activities-
               
Provision for depreciation
    65,916       57,904  
Amortization of regulatory assets, net
    59,910       87,664  
Purchased power cost recovery reconciliation
    15,372       -  
Amortization of lease costs
    28,394       28,535  
Deferred income taxes and investment tax credits, net
    32,658       17,267  
Accrued compensation and retirement benefits
    (3,542 )     (41,190 )
Accrued regulatory obligations
    19,172       -  
Electric service prepayment programs
    (4,634 )     (31,895 )
Cash collateral from suppliers
    6,469       -  
Pension trust contributions
    (103,035 )     -  
Decrease (increase) in operating assets-
               
Receivables
    128,688       (26,009 )
Prepayments and other current assets
    (2,553 )     2,065  
Decrease in operating liabilities-
               
Accounts payable
    (60,125 )     (27,463 )
Accrued taxes
    (17,196 )     (27,776 )
Accrued interest
    (59 )     (8,162 )
Other
    (8,596 )     (1,307 )
Net cash provided from operating activities
    236,850       195,332  
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing-
               
Long-term debt
    100,000       -  
Short-term borrowings, net
    74,514       189,148  
Redemptions and Repayments-
               
Long-term debt
    (101,088 )     (175,583 )
Dividend Payments-
               
Common stock
    (150,000 )     (315,000 )
Other
    (2,138 )     (445 )
Net cash used for financing activities
    (78,712 )     (301,880 )
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (108,253 )     (135,450 )
Sales of investment securities held in trusts
    207,280       115,988  
Purchases of investment securities held in trusts
    (214,592 )     (121,871 )
Loan repayments from associated companies, net
    134,975       234,577  
Cash investments
    7,070       5,143  
Other
    (1,216 )     8,144  
Net cash provided from investing activities
    25,264       106,531  
                 
Net increase (decrease) in cash and cash equivalents
    183,402       (17 )
Cash and cash equivalents at beginning of period
    146,343       732  
Cash and cash equivalents at end of period
  $ 329,745     $ 715  
                 
The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral
 
part of these statements.
               
 

 
10

 


THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
 
                         
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (LOSS)
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
September 30
   
September 30
 
   
2009
   
2008
   
2009
   
2008
 
STATEMENTS OF INCOME
 
(In thousands)
 
                         
REVENUES:
                       
Electric sales
  $ 417,900     $ 505,425     $ 1,307,592     $ 1,342,327  
Excise tax collections
    17,629       18,652       52,748       53,447  
Total revenues
    435,529       524,077       1,360,340       1,395,774  
                                 
EXPENSES:
                               
Purchased power from affiliates
    153,556       211,417       635,927       587,203  
Purchased power from non-affiliates
    87,689       28       208,849       3,097  
Other operating costs
    37,822       66,342       141,829       194,119  
Provision for depreciation
    17,753       17,677       53,885       54,497  
Amortization of regulatory assets
    39,313       48,155       325,630       124,936  
Deferral of new regulatory assets
    -       (16,176 )     (134,587 )     (71,443 )
General taxes
    37,752       36,722       112,749       109,230  
Total expenses
    373,885       364,165       1,344,282       1,001,639  
                                 
OPERATING INCOME
    61,644       159,912       16,058       394,135  
                                 
OTHER INCOME (EXPENSE):
                               
Investment income
    7,565       8,390       23,599       25,972  
Miscellaneous income (expense)
    645       (656 )     3,437       182  
Interest expense
    (34,740 )     (31,024 )     (100,819 )     (94,479 )
Capitalized interest
    27       200       145       584  
Total other expense
    (26,503 )     (23,090 )     (73,638 )     (67,741 )
                                 
INCOME (LOSS) BEFORE INCOME TAXES
    35,141       136,822       (57,580 )     326,394  
                                 
INCOME TAX EXPENSE (BENEFIT)
    9,755       42,977       (25,290 )     107,082  
                                 
NET INCOME (LOSS)
    25,386       93,845       (32,290 )     219,312  
                                 
Noncontrolling interest income
    418       458       1,295       1,501  
                                 
EARNINGS (LOSS) AVAILABLE TO PARENT
  $ 24,968     $ 93,387     $ (33,585 )   $ 217,811  
                                 
STATEMENTS OF COMPREHENSIVE INCOME
                               
                                 
NET INCOME (LOSS)
  $ 25,386     $ 93,845     $ (32,290 )   $ 219,312  
                                 
OTHER COMPREHENSIVE INCOME (LOSS):
                               
Pension and other postretirement benefits
    (48,024 )     (213 )     (154 )     (639 )
Unrealized loss on derivative hedges
    (1,451 )     -       (1,451 )     -  
Other comprehensive loss
    (49,475 )     (213 )     (1,605 )     (639 )
Income tax expense (benefit) related to other comprehensive income
    (17,854 )     (130 )     1,452       (239 )
Other comprehensive loss, net of tax
    (31,621 )     (83 )     (3,057 )     (400 )
                                 
COMPREHENSIVE INCOME (LOSS)
    (6,235 )     93,762       (35,347 )     218,912  
                                 
COMPREHENSIVE INCOME ATTRIBUTABLE
                               
TO NONCONTROLLING INTEREST
    418       458       1,295       1,501  
                                 
COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT
  $ (6,653 )   $ 93,304     $ (36,642 )   $ 217,411  
                                 
The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an
 
integral part of these statements.
                               
 

 
11

 


THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
 
             
CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
 
September 30,
   
December 31,
 
   
2009
   
2008
 
 
(In thousands)
 
ASSETS
           
CURRENT ASSETS:
           
Cash and cash equivalents
  $ 233     $ 226  
Receivables-
               
Customers (less accumulated provisions of $6,603,000 and
               
$5,916,000, respectively, for uncollectible accounts)
    241,469       276,400  
Associated companies
    134,558       113,182  
Other
    2,260       13,834  
Notes receivable from associated companies
    23,698       19,060  
Prepayments and other
    158,993       2,787  
      561,211       425,489  
UTILITY PLANT:
               
In service
    2,283,729       2,221,660  
Less - Accumulated provision for depreciation
    880,334       846,233  
      1,403,395       1,375,427  
Construction work in progress
    38,478       40,651  
      1,441,873       1,416,078  
OTHER PROPERTY AND INVESTMENTS:
               
Investment in lessor notes
    398,609       425,715  
Other
    264       10,249  
      398,873       435,964  
DEFERRED CHARGES AND OTHER ASSETS:
               
Goodwill
    1,688,521       1,688,521  
Regulatory assets
    592,206       783,964  
Property taxes
    71,500       71,500  
Other
    24,543       10,818  
      2,376,770       2,554,803  
    $ 4,778,727     $ 4,832,334  
LIABILITIES AND CAPITALIZATION
               
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $ 150,738     $ 150,688  
Short-term borrowings-
               
Associated companies
    135,023       227,949  
Accounts payable-
               
Associated companies
    221,456       106,074  
Other
    16,573       7,195  
Accrued taxes
    77,298       87,810  
Accrued interest
    43,749       13,932  
Other
    49,267       40,095  
      694,104       633,743  
CAPITALIZATION:
               
Common stockholder's equity
               
Common stock, without par value, authorized 105,000,000 shares -
               
67,930,743 shares outstanding
    884,415       878,785  
Accumulated other comprehensive loss
    (137,914 )     (134,857 )
Retained earnings
    576,369       859,954  
Total common stockholder's equity
    1,322,870       1,603,882  
Noncontrolling interest
    20,196       22,555  
Total equity
    1,343,066       1,626,437  
Long-term debt and other long-term obligations
    1,871,401       1,591,586  
      3,214,467       3,218,023  
NONCURRENT LIABILITIES:
               
Accumulated deferred income taxes
    662,422       704,270  
Accumulated deferred investment tax credits
    12,135       13,030  
Retirement benefits
    65,351       128,738  
Lease assignment payable to associated companies
    40,827       40,827  
Other
    89,421       93,703  
      870,156       980,568  
COMMITMENTS AND CONTINGENCIES (Note 9)
               
    $ 4,778,727     $ 4,832,334  
                 
                 
The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating
 
Company are an integral part of these balance sheets.
               
 

 
12

 
 
 
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
 
             
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
             
   
Nine Months Ended
 
   
September 30
 
   
2009
   
2008
 
   
(In thousands)
 
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net income (loss)
  $ (32,290 )   $ 219,312  
Adjustments to reconcile net income (loss) to net cash from operating activities-
         
Provision for depreciation
    53,885       54,497  
Amortization of regulatory assets
    325,630       124,936  
Deferral of new regulatory assets
    (134,587 )     (71,443 )
Purchased power cost recovery reconciliation
    (3,478 )     -  
Deferred income taxes and investment tax credits, net
    (41,939 )     4,623  
Accrued compensation and retirement benefits
    10,311       (3,291 )
Pension trust contribution
    (89,789 )     -  
Electric service prepayment programs
    (3,510 )     (17,551 )
Cash collateral from suppliers
    5,404       -  
Decrease (increase) in operating assets-
               
Receivables
    30,977       43,927  
Prepayments and other current assets
    (633 )     (37 )
Increase (decrease) in operating liabilities-
               
Accounts payable
    (32,240 )     (4,443 )
Accrued taxes
    (17,003 )     (19,613 )
Accrued interest
    29,816       23,990  
Other
    11,489       5,647  
Net cash provided from (used for) operating activities
    112,043       360,554  
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing-
               
Long-term debt
    298,398       -  
Redemptions and Repayments-
               
Long-term debt
    (558 )     (508 )
Short-term borrowings, net
    (111,128 )     (176,354 )
Dividend Payments-
               
Common stock
    (93,000 )     (150,000 )
Other
    (6,161 )     (2,955 )
Net cash provided from (used for) financing activities
    87,551       (329,817 )
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (73,577 )     (97,326 )
Restricted cash
    (155,573 )     -  
Loan repayments from (loans to) associated companies, net
    (4,638 )     30,624  
Redemption of lessor notes
    37,072       37,714  
Other
    (2,871 )     (1,744 )
Net cash used for investing activities
    (199,587 )     (30,732 )
                 
Net increase in cash and cash equivalents
    7       5  
Cash and cash equivalents at beginning of period
    226       232  
Cash and cash equivalents at end of period
  $ 233     $ 237  
                 
The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company
 
are an integral part of these statements.
               

 
13

 
 

THE TOLEDO EDISON COMPANY
 
                         
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (LOSS)
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
September 30
   
September 30
 
   
2009
   
2008
   
2009
   
2008
 
   
(In thousands)
 
STATEMENTS OF INCOME
                       
                         
REVENUES:
                       
Electric sales
  $ 206,086     $ 242,866     $ 663,082     $ 660,888  
Excise tax collections
    7,422       8,239       21,448       23,417  
Total revenues
    213,508       251,105       684,530       684,305  
                                 
EXPENSES:
                               
Purchased power from affiliates
    86,278       111,794       342,166       314,124  
Purchased power from non-affiliates
    56,494       15       115,275       1,833  
Other operating costs
    30,238       47,010       110,722       143,144  
Provision for depreciation
    7,847       7,682       23,136       24,648  
Amortization of regulatory assets, net
    9,253       25,878       30,921       57,840  
General taxes
    13,205       13,609       39,804       40,591  
Total expenses
    203,315       205,988       662,024       582,180  
                                 
OPERATING INCOME
    10,193       45,117       22,506       102,125  
                                 
OTHER INCOME (EXPENSE):
                               
Investment income
    9,302       5,580       22,315       17,285  
Miscellaneous expense
    (1,725 )     (1,523 )     (1,690 )     (4,982 )
Interest expense
    (10,854 )     (5,832 )     (25,649 )     (17,445 )
Capitalized interest
    46       19       138       144  
Total other expense
    (3,231 )     (1,756 )     (4,886 )     (4,998 )
                                 
INCOME BEFORE INCOME TAXES
    6,962       43,361       17,620       97,127  
                                 
INCOME TAX EXPENSE (BENEFIT)
    (138 )     12,174       3,123       27,614  
                                 
NET INCOME
    7,100       31,187       14,497       69,513  
                                 
Noncontrolling interest income
    14       6       17       10  
                                 
EARNINGS AVAILABLE TO PARENT
  $ 7,086     $ 31,181     $ 14,480     $ 69,503  
                                 
STATEMENTS OF COMPREHENSIVE INCOME
                               
                                 
NET INCOME
  $ 7,100     $ 31,187     $ 14,497     $ 69,513  
                                 
OTHER COMPREHENSIVE INCOME (LOSS):
                               
Pension and other postretirement benefits
    (24,201 )     (64 )     (5,052 )     (191 )
Change in unrealized gain on available-for-sale securities
    (11,633 )     (247 )     (15,181 )     (767 )
Other comprehensive loss
    (35,834 )     (311 )     (20,233 )     (958 )
Income tax benefit related to other comprehensive income
    (13,187 )     (108 )     (5,982 )     (294 )
Other comprehensive loss, net of tax
    (22,647 )     (203 )     (14,251 )     (664 )
                                 
COMPREHENSIVE INCOME (LOSS)
    (15,547 )     30,984       246       68,849  
                                 
COMPREHENSIVE INCOME ATTRIBUTABLE
                               
TO NONCONTROLLING INTEREST
    14       6       17       10  
                                 
COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT
  $ (15,561 )   $ 30,978     $ 229     $ 68,839  
                                 
The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of
 
these statements.
                               

 
14

 

THE TOLEDO EDISON COMPANY
 
             
CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
 
September 30,
   
December 31,
 
   
2009
   
2008
 
 
(In thousands)
 
ASSETS
           
CURRENT ASSETS:
           
Cash and cash equivalents
  $ 196,834     $ 14  
Receivables-
               
Customers
    485       751  
Associated companies
    44,103       61,854  
Other (less accumulated provisions of $207,000 and $203,000,
         
respectively, for uncollectible accounts)
    19,349       23,336  
Notes receivable from associated companies
    101,562       111,579  
Prepayments and other
    4,864       1,213  
      367,197       198,747  
UTILITY PLANT:
               
In service
    900,595       870,911  
Less - Accumulated provision for depreciation
    422,092       407,859  
      478,503       463,052  
Construction work in progress
    8,621       9,007  
      487,124       472,059  
OTHER PROPERTY AND INVESTMENTS:
               
Investment in lessor notes
    124,329       142,687  
Long-term notes receivable from associated companies
    36,993       37,233  
Nuclear plant decommissioning trusts
    75,152       73,500  
Other
    1,603       1,668  
      238,077       255,088  
DEFERRED CHARGES AND OTHER ASSETS:
               
Goodwill
    500,576       500,576  
Regulatory assets
    77,128       109,364  
Property taxes
    22,970       22,970  
Other
    55,579       51,315  
      656,253       684,225  
    $ 1,748,651     $ 1,610,119  
LIABILITIES AND CAPITALIZATION
               
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $ 222     $ 34  
Accounts payable-
               
Associated companies
    27,454       70,455  
Other
    9,373       4,812  
Notes payable to associated companies
    9,673       111,242  
Accrued taxes
    23,660       24,433  
Lease market valuation liability
    36,900       36,900  
Other
    37,231       22,489  
      144,513       270,365  
CAPITALIZATION:
               
Common stockholder's equity-
               
Common stock, $5 par value, authorized 60,000,000 shares -
         
29,402,054 shares outstanding
    147,010       147,010  
Other paid-in capital
    177,992       175,879  
Accumulated other comprehensive loss
    (47,623 )     (33,372 )
Retained earnings
    205,013       190,533  
Total common stockholder's equity
    482,392       480,050  
Noncontrolling interest
    2,692       2,675  
Total equity
    485,084       482,725  
Long-term debt and other long-term obligations
    608,669       299,626  
      1,093,753       782,351  
NONCURRENT LIABILITIES:
               
Accumulated deferred income taxes
    70,865       78,905  
Accumulated deferred investment tax credits
    6,476       6,804  
Lease market valuation liability
    245,425       273,100  
Retirement benefits
    62,155       73,106  
Asset retirement obligations
    31,757       30,213  
Lease assignment payable to associated companies
    30,529       30,529  
Other
    63,178       64,746  
      510,385       557,403  
COMMITMENTS AND CONTINGENCIES (Note 9)
               
    $ 1,748,651     $ 1,610,119  
                 
The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an
 
integral part of these balance sheets.
               

 
15

 


THE TOLEDO EDISON COMPANY
 
             
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
             
   
Nine Months Ended
 
   
September 30
 
   
2009
   
2008
 
   
(In thousands)
 
             
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net income
  $ 14,497     $ 69,513  
Adjustments to reconcile net income to net cash from operating activities-
               
Provision for depreciation
    23,136       24,648  
Amortization of regulatory assets, net
    30,921       57,840  
Purchased power cost recovery reconciliation
    570       -  
Deferred rents and lease market valuation liability
    (34,556 )     (32,918 )
Deferred income taxes and investment tax credits, net
    (2,242 )     (4,163 )
Accrued compensation and retirement benefits
    3,039       (196 )
Accrued regulatory obligations
    4,841       -  
Electric service prepayment programs
    (1,458 )     (8,566 )
Pension trust contribution
    (21,590 )     -  
Cash collateral from suppliers
    2,830       -  
Decrease (increase) in operating assets-
               
Receivables
    24,561       29,088  
Prepayments and other current assets
    109       (556 )
Increase (decrease) in operating liabilities-
               
Accounts payable
    (13,440 )     (177,527 )
Accrued taxes
    (5,057 )     (9,737 )
Accrued interest
    14,033       4,663  
Other
    (4,264 )     (587 )
Net cash provided from (used for) operating activities
    35,930       (48,498 )
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing-
               
Long-term debt
    297,422       -  
Short-term borrowings, net
    -       81,807  
Redemptions and Repayments-
               
Long-term debt
    (292 )     (26 )
Short-term borrowings, net
    (101,569 )     -  
Dividend Payments-
               
Common stock
    (25,000 )     (40,000 )
Other
    (351 )     -  
Net cash provided from financing activities
    170,210       41,781  
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (33,005 )     (44,695 )
Loan repayments from associated companies, net
    10,256       43,083  
Redemption of lessor notes
    18,358       11,989  
Sales of investment securities held in trusts
    171,061       28,774  
Purchases of investment securities held in trusts
    (173,214 )     (31,297 )
Other
    (2,776 )     (1,135 )
Net cash provided from (used for) investing activities
    (9,320 )     6,719  
                 
Net change in cash and cash equivalents
    196,820       2  
Cash and cash equivalents at beginning of period
    14       22  
Cash and cash equivalents at end of period
  $ 196,834     $ 24  
                 
The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an
 
integral part of these statements.
               

 
16

 


JERSEY CENTRAL POWER & LIGHT COMPANY
 
                         
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
September 30
   
September 30
 
   
2009
   
2008
   
2009
   
2008
 
   
(In thousands)
 
                         
REVENUES:
                       
Electric sales
  $ 854,108     $ 1,087,245     $ 2,312,089     $ 2,691,782  
Excise tax collections
    14,128       15,358       37,890       39,792  
Total revenues
    868,236       1,102,603       2,349,979       2,731,574  
                                 
EXPENSES:
                               
Purchased power
    509,035       720,996       1,414,226       1,751,854  
Other operating costs
    84,495       78,275       241,241       234,628  
Provision for depreciation
    26,565       23,205       76,969       70,030  
Amortization of regulatory assets
    96,051       102,954       262,900       280,980  
General taxes
    18,344       19,476       48,427       52,042  
Total expenses
    734,490       944,906       2,043,763       2,389,534  
                                 
OPERATING INCOME
    133,746       157,697       306,216       342,040  
                                 
OTHER INCOME (EXPENSE):
                               
Miscellaneous income
    1,301       (565 )     4,113       459  
Interest expense
    (29,593 )     (25,747 )     (87,132 )     (75,051 )
Capitalized interest
    139       257       419       963  
Total other expense
    (28,153 )     (26,055 )     (82,600 )     (73,629 )
                                 
INCOME BEFORE INCOME TAXES
    105,593       131,642       223,616       268,411  
                                 
INCOME TAXES
    43,435       55,752       95,834       115,623  
                                 
NET INCOME
    62,158       75,890       127,782       152,788  
                                 
OTHER COMPREHENSIVE INCOME (LOSS):
                               
Pension and other postretirement benefits
    (51,932 )     (3,449 )     (26,893 )     (10,347 )
Unrealized gain on derivative hedges
    69       69       207       207  
Other comprehensive loss
    (51,863 )     (3,380 )     (26,686 )     (10,140 )
Income tax benefit related to other comprehensive income
    (21,295 )     (1,469 )     (8,806 )     (4,408 )
Other comprehensive loss, net of tax
    (30,568 )     (1,911 )     (17,880 )     (5,732 )
                                 
TOTAL COMPREHENSIVE INCOME
  $ 31,590     $ 73,979     $ 109,902     $ 147,056  
                                 
The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral
 
part of these statements.
                               

 
17

 


JERSEY CENTRAL POWER & LIGHT COMPANY
 
             
CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
   
Setpember 30,
   
December 31,
 
   
2009
   
2008
 
   
(In thousands)
 
ASSETS
           
CURRENT ASSETS:
           
Cash and cash equivalents
  $ 1     $ 66  
Receivables-
               
Customers (less accumulated provisions of $3,789,000 and $3,230,000
               
respectively, for uncollectible accounts)
    339,025       340,485  
Associated companies
    147       265  
Other
    20,128       37,534  
Notes receivable - associated companies
    16,915       16,254  
Prepaid taxes
    94,140       10,492  
Other
    17,683       18,066  
      488,039       423,162  
UTILITY PLANT:
               
In service
    4,427,994       4,307,556  
Less - Accumulated provision for depreciation
    1,597,831       1,551,290  
      2,830,163       2,756,266  
Construction work in progress
    49,873       77,317  
      2,880,036       2,833,583  
OTHER PROPERTY AND INVESTMENTS:
               
Nuclear fuel disposal trust
    196,253       181,468  
Nuclear plant decommissioning trusts
    161,629       143,027  
Other
    2,174       2,145  
      360,056       326,640  
DEFERRED CHARGES AND OTHER ASSETS:
               
Goodwill
    1,810,936       1,810,936  
Regulatory assets
    949,814       1,228,061  
Other
    25,987       29,946  
      2,786,737       3,068,943  
    $ 6,514,868     $ 6,652,328  
LIABILITIES AND CAPITALIZATION
               
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $ 30,227     $ 29,094  
Short-term borrowings-
               
Associated companies
    6,614       121,380  
Accounts payable-
               
Associated companies
    17,189       12,821  
Other
    153,704       198,742  
Accrued taxes
    3,994       20,561  
Accrued interest
    30,143       9,197  
Other
    113,232       133,091  
      355,103       524,886  
CAPITALIZATION
               
Common stockholder's equity-
               
Common stock, $10 par value, authorized 16,000,000 shares-
               
13,628,447 shares outstanding
    136,284       144,216  
Other paid-in capital
    2,506,930       2,644,756  
Accumulated other comprehensive loss
    (234,418 )     (216,538 )
Retained earnings
    196,358       156,576  
Total common stockholder's equity
    2,605,154       2,729,010  
Long-term debt and other long-term obligations
    1,810,367       1,531,840  
      4,415,521       4,260,850  
NONCURRENT LIABILITIES:
               
Power purchase contract liability
    424,921       531,686  
Accumulated deferred income taxes
    700,187       689,065  
Nuclear fuel disposal costs
    196,454       196,235  
Asset retirement obligations
    99,954       95,216  
Retirement benefits
    131,621       190,182  
Other
    191,107       164,208  
      1,744,244       1,866,592  
COMMITMENTS AND CONTINGENCIES (Note 9)
               
    $ 6,514,868     $ 6,652,328  
                 
The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral
 
part of these balance sheets.
               

 
18

 


JERSEY CENTRAL POWER & LIGHT COMPANY
 
             
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
             
   
Nine Months Ended
 
   
September 30
 
   
2009
   
2008
 
   
(In thousands)
 
             
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net income
  $ 127,782     $ 152,788  
Adjustments to reconcile net income to net cash from operating activities -
               
Provision for depreciation
    76,969       70,030  
Amortization of regulatory assets
    262,900       280,980  
Deferred purchased power and other costs
    (106,340 )     (107,649 )
Deferred income taxes and investment tax credits, net
    40,989       1,051  
Accrued compensation and retirement benefits
    7,308       (32,087 )
Cash collateral received from (returned to) suppliers
    (210 )     23,138  
Pension trust contribution
    (100,000 )     -  
Decrease (increase) in operating assets-
               
Receivables
    18,984       (43,742 )
Prepaid taxes
    (83,648 )     (62,148 )
Other current assets
    110       234  
Increase (decrease) in operating liabilities-
               
Accounts payable
    (40,670 )     36,099  
Accrued taxes
    (13,399 )     2,082  
Accrued interest
    20,946       17,276  
Tax collections payable
    (9,714 )     (12,493 )
Other
    12,606       (466 )
Net cash provided from operating activities
    214,613       325,093  
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing-
               
Long-term debt
    299,619       -  
Short-term borrowings, net
    -       12,236  
Redemptions and Repayments-
               
Long-term debt
    (20,570 )     (19,138 )
Common Stock
    (150,000 )     -  
Short-term borrowings, net
    (114,766 )     -  
Dividend Payments-
               
Common stock
    (88,000 )     (186,000 )
Other
    (2,275 )     -  
Net cash used for financing activities
    (75,992 )     (192,902 )
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (121,342 )     (136,265 )
Proceeds from asset sales
    -       20,000  
Loans to associated companies, net
    (660 )     553  
Sales of investment securities held in trusts
    338,684       186,564  
Purchases of investment securities held in trusts
    (351,216 )     (199,699 )
Other
    (4,152 )     (3,400 )
Net cash used for investing activities
    (138,686 )     (132,247 )
                 
Net decrease in cash and cash equivalents
    (65 )     (56 )
Cash and cash equivalents at beginning of period
    66       94  
Cash and cash equivalents at end of period
  $ 1     $ 38  
                 
The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company
 
are an integral part of these statements.
               

 
19

 


METROPOLITAN EDISON COMPANY
 
                         
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (LOSS)
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
September 30
   
September 30
 
   
2009
   
2008
   
2009
   
2008
 
   
(In thousands)
 
                         
REVENUES:
                       
Electric sales
  $ 424,901     $ 434,742     $ 1,194,609     $ 1,188,171  
Gross receipts tax collections
    20,612       20,793       58,181       59,669  
Total revenues
    445,513       455,535       1,252,790       1,247,840  
                                 
EXPENSES:
                               
Purchased power from affiliates
    94,768       81,846       273,497       233,496  
Purchased power from non-affiliates
    142,495       163,853       389,705       446,928  
Other operating costs
    63,654       126,659       221,320       350,704  
Provision for depreciation
    13,262       11,394       38,320       33,446  
Amortization (deferral) of regulatory assets, net
    84,631       3,680       173,770       (10,162 )
General taxes
    22,540       23,030       66,509       64,887  
Total expenses
    421,350       410,462       1,163,121       1,119,299  
                                 
OPERATING INCOME
    24,163       45,073       89,669       128,541  
                                 
OTHER INCOME (EXPENSE):
                               
Interest income
    2,169       4,016       8,124       14,368  
Miscellaneous income
    1,068       88       2,982       568  
Interest expense
    (14,380 )     (11,014 )     (42,502 )     (33,666 )
Capitalized interest
    47       93       124       73  
Total other expense
    (11,096 )     (6,817 )     (31,272 )     (18,657 )
                                 
INCOME BEFORE INCOME TAXES
    13,067       38,256       58,397       109,884  
                                 
INCOME TAXES
    2,324       16,270       21,027       45,866  
                                 
NET INCOME
    10,743       21,986       37,370       64,018  
                                 
OTHER COMPREHENSIVE INCOME (LOSS):
                               
Pension and other postretirement benefits
    (31,365 )     (2,233 )     557       (6,699 )
Unrealized gain on derivative hedges
    84       84       252       252  
Other comprehensive income (loss)
    (31,281 )     (2,149 )     809       (6,447 )
Income tax expense (benefit) related to other comprehensive income
    (13,112 )     (971 )     2,273       (2,912 )
Other comprehensive loss, net of tax
    (18,169 )     (1,178 )     (1,464 )     (3,535 )
                                 
TOTAL COMPREHENSIVE INCOME (LOSS)
  $ (7,426 )   $ 20,808     $ 35,906     $ 60,483  
                                 
The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral
         
part of these statements.
                               
 

 
20

 


METROPOLITAN EDISON COMPANY
 
             
CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
   
September 30,
   
December 31,
 
   
2009
   
2008
 
   
(In thousands)
 
ASSETS
           
CURRENT ASSETS:
           
Cash and cash equivalents
  $ 124     $ 144  
Receivables-
               
Customers (less accumulated provisions of $3,880,000 and $3,616,000,
               
respectively, for uncollectible accounts)
    165,519       159,975  
Associated companies
    43,462       17,034  
Other
    11,472       19,828  
Notes receivable from associated companies
    18,032       11,446  
Prepaid taxes
    29,895       6,121  
Other
    4,650       1,621  
      273,154       216,169  
UTILITY PLANT:
               
In service
    2,141,513       2,065,847  
Less - Accumulated provision for depreciation
    800,750       779,692  
      1,340,763       1,286,155  
Construction work in progress
    11,718       32,305  
      1,352,481       1,318,460  
OTHER PROPERTY AND INVESTMENTS:
               
Nuclear plant decommissioning trusts
    258,475       226,139  
Other
    981       976  
      259,456       227,115  
DEFERRED CHARGES AND OTHER ASSETS:
               
Goodwill
    416,499       416,499  
Regulatory assets
    403,690       412,994  
Power purchase contract asset
    186,661       300,141  
Other
    33,977       31,031  
      1,040,827       1,160,665  
    $ 2,925,918     $ 2,922,409  
LIABILITIES AND CAPITALIZATION
               
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $ 128,500     $ 28,500  
Short-term borrowings-
               
Associated companies
    -       15,003  
Other
    -       250,000  
Accounts payable-
               
Associated companies
    26,817       28,707  
Other
    39,927       55,330  
Accrued taxes
    5,143       16,238  
Accrued interest
    11,756       6,755  
Other
    30,354       30,647  
      242,497       431,180  
CAPITALIZATION:
               
Common stockholder's equity-
               
Common stock, without par value, authorized 900,000 shares-
               
859,500 shares outstanding
    1,197,007       1,196,172  
Accumulated other comprehensive loss
    (142,448 )     (140,984 )
Accumulated deficit
    (13,754 )     (51,124 )
Total common stockholder's equity
    1,040,805       1,004,064  
Long-term debt and other long-term obligations
    713,843       513,752  
      1,754,648       1,517,816  
NONCURRENT LIABILITIES:
               
Accumulated deferred income taxes
    448,951       387,757  
Accumulated deferred investment tax credits
    7,427       7,767  
Nuclear fuel disposal costs
    44,378       44,328  
Asset retirement obligations
    177,335       170,999  
Retirement benefits
    31,753       145,218  
Power purchase contract liability
    151,815       150,324  
Other
    67,114       67,020  
      928,773       973,413  
COMMITMENTS AND CONTINGENCIES (Note 9)
               
    $ 2,925,918     $ 2,922,409  
                 
The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral
 
part of these balance sheets.
               

 
21

 


METROPOLITAN EDISON COMPANY
 
             
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
             
   
Nine Months Ended
 
   
September 30
 
   
2009
   
2008
 
   
(In thousands)
 
             
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net income
  $ 37,370     $ 64,018  
Adjustments to reconcile net income to net cash from operating activities-
         
Provision for depreciation
    38,320       33,446  
Amortization (deferral) of regulatory assets, net
    173,770       (10,162 )
Deferred costs recoverable as regulatory assets
    (70,044 )     (9,673 )
Deferred income taxes and investment tax credits, net
    59,393       39,919  
Accrued compensation and retirement benefits
    6,712       (18,948 )
Pension trust contribution
    (123,521 )     -  
Cash collateral
    (6,800 )     -  
Decrease (Increase) in operating assets-
               
Receivables
    (23,370 )     (19,751 )
Prepayments and other current assets
    (22,614 )     (4,144 )
Increase (decrease) in operating liabilities-
               
Accounts payable
    (17,293 )     (9,250 )
Accrued taxes
    (11,095 )     (13,285 )
Accrued interest
    5,001       495  
Other
    11,891       13,510  
Net cash provided from operating activities
    57,720       66,175  
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing-
               
Long-term debt
    300,000       28,500  
Short-term borrowings, net
    -       29,959  
Redemptions and Repayments-
               
Long-term debt
    -       (28,640 )
Short-term borrowings, net
    (265,003 )     -  
Other
    (2,268 )     -  
Net cash provided from financing activities
    32,729       29,819  
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (73,106 )     (87,536 )
Sales of investment securities held in trusts
    88,802       131,915  
Purchases of investment securities held in trusts
    (95,982 )     (140,429 )
Loans from (to) associated companies, net
    (6,586 )     1,163  
Other
    (3,597 )     (1,113 )
Net cash used for investing activities
    (90,469 )     (96,000 )
                 
Net decrease in cash and cash equivalents
    (20 )     (6 )
Cash and cash equivalents at beginning of period
    144       135  
Cash and cash equivalents at end of period
  $ 124     $ 129  
                 
The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral
 
part of these statements.
               

 
22

 


PENNSYLVANIA ELECTRIC COMPANY
 
                         
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (LOSS)
 
(Unaudited)
 
                         
   
Three Months Ended
   
Nine Months Ended
 
   
September 30
   
September 30
 
   
2009
   
2008
   
2009
   
2008
 
   
(In thousands)
 
REVENUES:
                       
Electric sales
  $ 340,246     $ 372,576     $ 1,028,420     $ 1,083,986  
Gross receipts tax collections
    15,246       17,200       47,342       52,704  
Total revenues
    355,492       389,776       1,075,762       1,136,690  
                                 
EXPENSES:
                               
Purchased power from affiliates
    81,191       68,743       249,438       214,775  
Purchased power from non-affiliates
    144,777       161,913       397,260       442,906  
Other operating costs
    47,785       54,727       171,375       175,904  
Provision for depreciation
    15,038       14,097       45,074       40,531  
Amortization of regulatory assets, net
    17,201       23,415       44,090       55,346  
General taxes
    17,230       20,285       56,074       60,485  
Total expenses
    323,222       343,180       963,311       989,947  
                                 
OPERATING INCOME
    32,270       46,596       112,451       146,743  
                                 
OTHER INCOME (EXPENSE):
                               
Miscellaneous income
    1,156       (93 )     2,865       774  
Interest expense
    (11,614 )     (14,934 )     (36,690 )     (45,157 )
Capitalized interest
    23       57       74       (679 )
Total other expense
    (10,435 )     (14,970 )     (33,751 )     (45,062 )
                                 
INCOME BEFORE INCOME TAXES
    21,835       31,626       78,700       101,681  
                                 
INCOME TAXES
    6,039       9,058       29,393       39,324  
                                 
NET INCOME
    15,796       22,568       49,307       62,357  
                                 
OTHER COMPREHENSIVE INCOME (LOSS):
                               
Pension and other postretirement benefits
    (79,579 )     (3,474 )     (47,224 )     (10,421 )
Unrealized gain on derivative hedges
    17       16       49       48  
Change in unrealized gain on available-for-sale securities
    19       2       3       (8 )
Other comprehensive loss
    (79,543 )     (3,456 )     (47,172 )     (10,381 )
Income tax benefit related to other comprehensive loss
    (33,141 )     (1,510 )     (16,986 )     (4,536 )
Other comprehensive loss, net of tax
    (46,402 )     (1,946 )     (30,186 )     (5,845 )
                                 
TOTAL COMPREHENSIVE INCOME (LOSS)
  $ (30,606 )   $ 20,622     $ 19,121     $ 56,512  
                                 
The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part
 
of these statements.
                               

 
23

 


PENNSYLVANIA ELECTRIC COMPANY
 
             
CONSOLIDATED BALANCE SHEETS
 
(Unaudited)
 
   
September 30,
   
December 31,
 
   
2009
   
2008
 
   
(In thousands)
 
ASSETS
           
CURRENT ASSETS:
           
Cash and cash equivalents
  $ 9     $ 23  
Receivables-
               
Customers (less accumulated provisions of $2,844,000 and $3,121,000,
               
respectively, for uncollectible accounts)
    124,178       146,831  
Associated companies
    98,061       65,610  
Other
    14,116       26,766  
Notes receivable from associated companies
    14,186       14,833  
Prepaid taxes
    41,916       16,310  
Other
    641       1,517  
      293,107       271,890  
UTILITY PLANT:
               
In service
    2,397,432       2,324,879  
Less - Accumulated provision for depreciation
    891,835       868,639  
      1,505,597       1,456,240  
Construction work in progress
    28,729       25,146  
      1,534,326       1,481,386  
OTHER PROPERTY AND INVESTMENTS:
               
Nuclear plant decommissioning trusts
    137,008       115,292  
Non-utility generation trusts
    119,163       116,687  
Other
    290       293  
      256,461       232,272  
DEFERRED CHARGES AND OTHER ASSETS:
               
Goodwill
    768,628       768,628  
Power purchase contract asset
    23,979       119,748  
Regulatory assets
    3,433       -  
Other
    18,814       18,658  
      814,854       907,034  
    $ 2,898,748     $ 2,892,582  
LIABILITIES AND CAPITALIZATION
               
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $ 80,000     $ 145,000  
Short-term borrowings-
               
Associated companies
    41,632       31,402  
Other
    -       250,000  
Accounts payable-
               
Associated companies
    27,126       63,692  
Other
    41,210       48,633  
Accrued taxes
    6,104       13,264  
Accrued interest
    10,561       13,131  
Other
    27,237       31,730  
      233,870       596,852  
CAPITALIZATION:
               
Common stockholder's equity-
               
Common stock, $20 par value, authorized 5,400,000 shares-
               
4,427,577 shares outstanding
    88,552       88,552  
Other paid-in capital
    913,374       912,441  
Accumulated other comprehensive loss
    (158,183 )     (127,997 )
Retained earnings
    75,420       76,113  
Total common stockholder's equity
    919,163       949,109  
Long-term debt and other long-term obligations
    1,096,745       633,132  
      2,015,908       1,582,241  
NONCURRENT LIABILITIES:
               
Regulatory liabilities
    -       136,579  
Accumulated deferred income taxes
    220,925       169,807  
Retirement benefits
    168,767       172,718  
Asset retirement obligations
    90,334       87,089  
Power purchase contract liability
    108,160       83,600  
Other
    60,784       63,696  
      648,970       713,489  
COMMITMENTS AND CONTINGENCIES (Note 9)
               
    $ 2,898,748     $ 2,892,582  
                 
The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company
 
are an integral part of these balance sheets.
               

 
24

 


PENNSYLVANIA ELECTRIC COMPANY
 
             
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
             
   
Nine Months Ended
 
   
September 30
 
   
2009
   
2008
 
   
(In thousands)
 
             
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net income
  $ 49,307     $ 62,357  
Adjustments to reconcile net income to net cash from operating activities-
         
Provision for depreciation
    45,074       40,531  
Amortization of regulatory assets, net
    44,090       55,346  
Deferred costs recoverable as regulatory assets
    (76,953 )     (20,304 )
Deferred income taxes and investment tax credits, net
    56,144       68,377  
Accrued compensation and retirement benefits
    6,271       (21,190 )
Pension trust contribution
    (60,000 )     -  
Decrease (increase) in operating assets-
               
Receivables
    3,687       (42,971 )
Prepayments and other current assets
    (24,730 )     (28,730 )
Increase (decrease) in operating liabilities-
               
Accounts payable
    (8,988 )     (8,437 )
Accrued taxes
    (7,015 )     (11,521 )
Accrued interest
    (2,570 )     867  
Other
    13,392       14,663  
Net cash provided from operating activities
    37,709       108,988  
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
New Financing-
               
Long-term debt
    498,583       45,000  
Short-term borrowings, net
    -       65,590  
Redemptions and Repayments-
               
Long-term debt
    (100,000 )     (45,332 )
Short-term borrowings, net
    (239,770 )     -  
Dividend Payments-
               
Common stock
    (85,000 )     (65,000 )
Other
    (3,865 )     -  
Net cash provided from financing activities
    69,948       258  
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Property additions
    (92,070 )     (94,810 )
Loan repayments from associated companies, net
    647       907  
Sales of investment securities held in trust
    80,986       84,499  
Purchases of investment securities held in trust
    (91,105 )     (96,950 )
Other
    (6,129 )     (2,902 )
Net cash used for investing activities
    (107,671 )     (109,256 )
                 
Net decrease in cash and cash equivalents
    (14 )     (10 )
Cash and cash equivalents at beginning of period
    23       46  
Cash and cash equivalents at end of period
  $ 9     $ 36  
                 
The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an
 
 integral part of these statements.
               
 

 
25

 


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. ORGANIZATION AND BASIS OF PRESENTATION

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

FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, the FERC and, as applicable, the PUCO, the PPUC and the NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period. In preparing the financial statements, FirstEnergy and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through November 6, 2009, the date the financial statements were issued.

These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 2008 for FirstEnergy, FES and the Utilities. The consolidated unaudited financial statements of FirstEnergy, FES and each of the Utilities reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform to the current year presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.

FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 7) 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 September 30, 2009 and for the three-month and nine-month periods ended September 30, 2009 and 2008, have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their report (dated November 6, 2009) is included herein. The report of PricewaterhouseCoopers LLP states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited financial information because that report is not a "report" or a "part" of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Securities Act of 1933.

2.  EARNINGS PER SHARE

Basic earnings per share of common stock are computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. The following table reconciles basic and diluted earnings per share of common stock:

   
Three Months Ended
 
Nine Months Ended
 
Reconciliation of Basic and Diluted Earnings per Share
 
September 30
 
September 30
 
of Common Stock
 
2009
 
2008
 
2009
 
2008
 
   
(In millions, except per share amounts)
 
Earnings available to FirstEnergy Corp.
 
$
234
 
$
471
 
$
768
 
$
1,010
 
                           
Average shares of common stock outstanding - Basic
   
304
   
304
   
304
   
304
 
Assumed exercise of dilutive stock options and awards
   
2
   
3
   
2
   
3
 
Average shares of common stock outstanding - Diluted
   
306
   
307
   
306
   
307
 
                           
Basic earnings per share of common stock
 
$
.77
 
$
1.55
 
$
2.52
 
$
3.32
 
Diluted earnings per share of common stock
 
$
.77
 
$
1.54
 
$
2.51
 
$
3.29
 


 
26

 


3. GOODWILL

In a business combination, the excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed is recognized as goodwill. FirstEnergy evaluates its goodwill for impairment at least annually and more frequently as indicators of impairment arise. FirstEnergy's 2009 annual evaluation was completed in the third quarter of 2009 with no impairment indicated.

4. FAIR VALUE OF FINANCIAL INSTRUMENTS

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

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

   
September 30, 2009
 
December 31, 2008
 
   
Carrying
 
Fair
 
Carrying
 
Fair
 
   
Value
 
Value
 
Value
 
Value
 
   
(In millions)
 
FirstEnergy
 
$
13,675
 
$
14,483
 
$
11,585
 
$
11,146
 
FES
   
4,233
   
4,304
   
2,552
   
2,528
 
OE
   
1,169
   
1,318
   
1,232
   
1,223
 
CEI
   
1,900
   
2,033
   
1,741
   
1,618
 
TE
   
600
   
656
   
300
   
244
 
JCP&L
   
1,849
   
1,977
   
1,569
   
1,520
 
Met-Ed
   
842
   
911
   
542
   
519
 
Penelec
   
1,179
   
1,221
   
779
   
721
 

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

(B)
INVESTMENTS

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

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

Available-For-Sale Securities

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

 
27

 


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

   
September 30, 2009(1)
 
December 31, 2008(2)
 
   
Cost
 
Unrealized
 
Unrealized
 
Fair
 
Cost
 
Unrealized
 
Unrealized
 
Fair
 
   
Basis
 
Gains
 
Losses
 
Value
 
Basis
 
Gains
 
Losses
 
Value
 
Debt securities
 
(In millions)
 
FirstEnergy(3)
 
$
576
 
$
25
 
$
-
 
$
601
 
$
1,078
 
$
56
 
$
-
 
$
1,134
 
FES
   
7
   
1
   
-
   
8
   
401
   
28
   
-
   
429
 
OE
   
2
   
-
   
-
   
2
   
86
   
9
   
-
   
95
 
TE
   
-
   
-
   
-
   
-
   
66
   
8
   
-
   
74
 
JCP&L
   
266
   
13
   
-
   
279
   
249
   
9
   
-
   
258
 
Met-Ed
   
121
   
6
   
-
   
127
   
111
   
4
   
-
   
115
 
Penelec
   
180
   
5
   
-
   
185
   
164
   
3
   
-
   
167
 
                                                   
Equity securities
                                                 
FirstEnergy
 
$
245
 
$
33
 
$
-
 
$
278
 
$
589
 
$
39
 
$
-
 
$
628
 
FES
   
-
   
-
   
-
   
-
   
355
   
25
   
-
   
380
 
OE
   
-
   
-
   
-
   
-
   
17
   
1
   
-
   
18
 
JCP&L
   
72
   
8
   
-
   
80
   
64
   
2
   
-
   
66
 
Met-Ed
   
114
   
18
   
-
   
132
   
101
   
9
   
-
   
110
 
Penelec
   
59
   
7
   
-
   
66
   
51
   
2
   
-
   
53
 
                                                   
(1) Excludes cash balances of $1,291 million at FirstEnergy, $1,094 million at FES, $2 million at JCP&L, $120 million at OE, $5 million at Penelec and $75 million at TE.
(2) Excludes cash balances of $244 million at FirstEnergy, $225 million at FES, $12 million at Penelec, $4 million at OE and $1 million at Met-Ed.
(3) Includes fair values as of September 30, 2009 and December 31, 2008 of $557 million and $953 million of government obligations, $44 million and $175 million of corporate debt and $1 million and $6 million of mortgage backed securities.
 

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

   
FirstEnergy
 
FES
 
OE
 
TE
 
JCP&L
 
Met-Ed
 
Penelec
 
   
(In millions)
 
Proceeds from sales
 
$
3,040
 
$
2,153
 
$
207
 
$
171
 
$
339
 
$
89
 
$
81
 
Realized gains
   
186
   
162
   
11
   
7
   
4
   
1
   
1
 
Realized losses
   
96
   
62
   
3
   
-
   
11
   
13
   
7
 
Interest and dividend income
   
47
   
22
   
4
   
2
   
10
   
5
   
4
 

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

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

During the three-month period ended September 30, 2009, FES recognized $135 million of realized gains resulting from the sale of securities held in the nuclear decommissioning trust.

Held-To-Maturity Securities

The following table provides the amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities (except for investments of $271 million and $293 million that are not required to be disclosed) as of September 30, 2009 and December 31, 2008:

   
September 30, 2009
 
December 31, 2008
 
   
Cost
 
Unrealized
 
Unrealized
 
Fair
 
Cost
 
Unrealized
 
Unrealized
 
Fair
 
   
Basis
 
Gains
 
Losses
 
Value
 
Basis
 
Gains
 
Losses
 
Value
 
Debt securities
 
(In millions)
 
FirstEnergy
 
$
621
 
$
91
 
$
-
 
$
712
 
$
673
 
$
14
 
$
13
 
$
674
 
OE
   
230
   
57
   
-
   
287
   
240
   
-
   
13
   
227
 
CEI
   
389
   
34
   
-
   
423
   
426
   
9
   
-
   
435
 


 
28

 


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

   
September 30, 2009
 
December 31, 2008
 
   
Carrying
 
Fair
 
Carrying
 
Fair
 
   
Value
 
Value
 
Value
 
Value
 
Notes receivable
 
(In millions)
 
FirstEnergy
 
$
45
 
$
42
 
$
45
 
$
44
 
FES
   
4
   
4
   
75
   
74
 
OE
   
193
   
234
   
257
   
294
 
TE
   
161
   
180
   
180
   
189
 

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

(C)
RECURRING FAIR VALUE MEASUREMENTS

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

The following tables set forth financial assets and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of September 30, 2009 and December 31, 2008. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. FirstEnergy's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the fair valuation of assets and liabilities and their placement within the fair value hierarchy levels.

Recurring Fair Value Measures as of September 30, 2009
   
Level 1 - Assets
   
Level 1 - Liabilities
 
(In millions)
   
Derivatives
 
Available-for-
Sale Securities(1)
 
Other Investments
 
Total
   
Derivatives
 
NUG
Contracts(2)
 
Total
FirstEnergy
$
-
$
278
$
-
$
278
 
$
15
$
-
$
15
FES
 
-
 
1
 
-
 
1
   
15
 
-
 
15
OE
 
-
 
-
 
-
 
-
   
-
 
-
 
-
JCP&L
 
-
 
81
 
-
 
81
   
-
 
-
 
-
Met-Ed
 
-
 
125
 
-
 
125
   
-
 
-
 
-
Penelec
 
-
 
71
 
-
 
71
   
-
 
-
 
-
                               
   
Level 2 - Assets
   
Level 2 - Liabilities
   
Derivatives
 
Available-for-
Sale Securities(1)
 
Other Investments
 
Total
   
Derivatives
 
NUG
Contracts(2)
 
Total
FirstEnergy
$
32
$
1,896
$
78
$
2,006
 
$
6
$
-
$
6
FES
 
13
 
1,103
 
-
 
1,116
   
5
 
-
 
5
OE
 
-
 
123
 
-
 
123
   
-
 
-
 
-
TE
 
-
 
75
 
-
 
75
   
-
 
-
 
-
JCP&L
 
5
 
276
 
-
 
281
   
-
 
-
 
-
Met-Ed
 
9
 
134
 
-
 
143
   
-
 
-
 
-
Penelec
 
5
 
185
 
-
 
190
   
-
 
-
 
-
                               
   
Level 3 - Assets
   
Level 3 - Liabilities
   
Derivatives
 
Available-for-
Sale Securities(1)
 
NUG
Contracts(2)
 
Total
   
Derivatives
 
NUG
Contracts(2)
 
Total
FirstEnergy
$
-
$
-
$
220
$
220
 
$
-
$
685
$
685
JCP&L
 
-
 
-
 
9
 
9
   
-
 
425
 
425
Met-Ed
 
-
 
-
 
187
 
187
   
-
 
152
 
152
Penelec
 
-
 
-
 
24
 
24
   
-
 
108
 
108

 
(1)
Consists of investments in nuclear decommissioning trusts, spent nuclear fuel trusts and NUG trusts. Balance excludes $2 million of receivables, payables
and accrued income.
(2)     NUG contracts are completely offset by regulatory assets and do not impact earnings.

 
29

 



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

 
(1)
Consists of investments in nuclear decommissioning trusts, spent nuclear fuel trusts and NUG trusts. Balance excludes $5 million of receivables, payables
and accrued income.
(2)     NUG contracts are completely offset by regulatory assets and do not impact earnings.

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

The following tables set forth a reconciliation of changes in the fair value of NUG contracts classified as Level 3 in the fair value hierarchy for the three and nine months ended September 30, 2009 and 2008 (in millions):

   
FirstEnergy
 
JCP&L
 
Met-Ed
 
Penelec
 
Balance as of January 1, 2009
 
$
(332
)
$
(518
)
$
150
 
$
36
 
    Settlements(1)
   
273
   
132
   
63
   
78
 
    Unrealized gains (losses)(1)
   
(406)
   
(30)
   
(178)
   
(198)
 
    Net transfers to (from) Level 3
   
-
   
-
   
-
   
-
 
Balance as of September 30, 2009
 
$
(465)
 
$
(416)
 
$
35
 
$
(84)
 
 
                         
Change in unrealized gains (losses) relating to 
instruments held as of September 30, 2009
 
$
(406)
 
$
(30)
 
 
$
 
(178)
 
 
$
 
(198)
 
                           
Balance as of July 1, 2009
 
$
(536
)
$
(466
)
$
23
 
$
(93
)
    Settlements(1)
   
93
   
42
   
20
   
31
 
    Unrealized gains (losses)(1)
   
(22)
   
8
   
(8)
   
(22)
 
    Net transfers to (from) Level 3
   
-
   
-
   
-
   
-
 
Balance as of September 30, 2009
 
$
(465)
 
$
(416)
 
$
35
 
$
(84)
 
                           
Change in unrealized gains (losses) relating to
instruments held as of September 30, 2009
 
$
(22)
 
$
8
 
 
$
 
(8)
 
 
$
 
(22)
 

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


 
30

 


   
FirstEnergy
 
JCP&L
 
Met-Ed
 
Penelec
 
Balance as of January 1, 2008
 
$
(803
)
$
(750
)
$
(28
)
$
(25
)
    Settlements(1)
   
167
   
152
   
(5)
   
20
 
    Unrealized gains (losses)(1)
   
314
   
(43)
   
236
   
121
 
    Net transfers to (from) Level 3
   
-
   
-
   
-
   
-
 
Balance as of September 30, 2008
 
$
(322)
 
$
(641)
 
$
203
 
$
116
 
 
                         
Change in unrealized gains (losses) relating to
 instruments held as of September 30, 2008
 
$
314
 
$
(43)
 
 
$
 
236
 
 
$
 
121
 
                           
Balance as of July 1, 2008
 
$
(17
)
$
(644
)
$
350
 
$
278
 
    Settlements(1)
   
57
   
57
   
(7)
   
7
 
    Unrealized gains (losses)(1)
   
(362)
   
(54)
   
(140)
   
(169)
 
    Net transfers to (from) Level 3
   
-
   
-
   
-
   
-
 
Balance as of September 30, 2008
 
$
(322)
 
$
(641)
 
$
203
 
$
116
 
                           
Change in unrealized gains (losses) relating to
instruments held as of September 30, 2008
 
$
(362)
 
$
(54)
 
 
$
 
(140)
 
 
$
 
(169)
 

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

5. DERIVATIVE INSTRUMENTS

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

FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value unless they meet the normal purchase and normal sales criteria. Derivatives that meet those criteria are accounted for at cost. The changes in the fair value of derivative instruments that do not meet the normal purchase and normal sales criteria are included in other expense, unrealized gain (loss) on derivative hedges in other comprehensive income (loss), or as part of the value of the hedged item.

Interest Rate Derivatives

Under the revolving credit facility, FirstEnergy, and its subsidiaries, incur variable interest charges based on LIBOR. FirstEnergy currently holds swaps with a notional value of $200 million to hedge against changes in associated interest rates. Hedges with a notional value of $100 million expire in November 2009 and $100 million expire in January 2010. The swaps are accounted for as cash flow hedges. As of September 30, 2009, the fair value of outstanding swaps was $(2) million.

FirstEnergy uses forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. For the three months and nine months ended September 30, 2009, FirstEnergy terminated forward swaps with a notional value of $2.3 billion and $2.4 billion, respectively. FirstEnergy recognized losses of approximately $17 million and $18 million, respectively -- of which the ineffective portion recognized as an adjustment to interest expense was immaterial. The remaining effective portions will be amortized to interest expense over the life of the hedged debt.

As of September 30, 2009 and December 31, 2008, the fair value of outstanding interest rate derivatives was $(2) million and $(3) million, respectively. Interest rate derivatives are included in "Other Noncurrent Liabilities" on FirstEnergy’s consolidated balance sheets. The effects of interest rate derivatives on the consolidated statements of income and comprehensive income during the three months and nine months ended September 30, 2009 and 2008 were:

 
31

 


     
Three Months Ended
 
Nine Months Ended
 
     
September 30
 
September 30
 
     
2009
 
2008
 
2009
 
2008
 
     
(In millions)
 
Effective Portion
                         
 
Loss Recognized in AOCL
 
$
(17)
 
$
(2)
 
$
(18)
 
$
(11)
 
 
Loss Reclassified from AOCL into Interest Expense
   
(26)
   
(4)
   
(37)
   
(11)
 
Ineffective Portion
                         
 
Loss Recognized in Interest Expense
   
-
   
-
   
-
   
(5)
 

Total unamortized losses included in AOCL associated with prior interest rate hedges totaled $94 million ($57 million net of tax) as of September 30, 2009. Based on current estimates, approximately $11 million will be amortized to interest expense during the next twelve months. FirstEnergy’s interest rate swaps do not include any contingent credit risk related features.

Commodity Derivatives

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

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

Derivative Assets
 
Derivative Liabilities
   
Fair Value
     
Fair Value
   
September 30
 
December 31
     
September 30
 
December 31
   
2009
 
2008
     
2009
 
2008
Cash Flow Hedges
 
(In millions)
 
Cash Flow Hedges
 
(In millions)
Electricity Forwards
         
Electricity Forwards
       
 
Current Assets
$
13
$
11
   
Current Liabilities
$
5
$
27
Natural Gas Futures
         
Natural Gas Futures
       
 
Current Assets
 
-
 
-
   
Current Liabilities
 
8
 
4
 
Long-Term Deferred Charges
 
-
 
-
   
Noncurrent Liabilities
 
1
 
5
Other
         
Other
       
 
Current Assets
 
-
 
-
   
Current Liabilities
5
 
12
 
Long-Term Deferred Charges
 
-
 
-
   
Noncurrent Liabilities
 
2
 
4
   
$
13
$
11
   
$
21
 
52
                       
               
Derivative Assets
 
Derivative Liabilities
     
Fair Value
     
Fair Value
     
September 30 2009
 
December 31 2008
     
September 30 2009
 
December 31 2008
Economic Hedges
 
(In millions)
 
Economic Hedges
 
(In millions)
NUG Contracts
     
NUG Contracts
   
 
Power Purchase
           
Power Purchase
       
 
Contract Asset
$
220
$
434
   
Contract Liability
$
685
$
766
Other
         
Other
       
 
Current Assets
 
-
 
1
   
Current Liabilities
 
-
 
1
 
Long-Term Deferred Charges
 
19
 
28
   
 Noncurrent Liabilities
 
-
 
-
   
$
239
$
463
   
$
685
$
767
Total Commodity Derivatives
$
252
$
474
 
Total Commodity Derivatives
$
706
$
819


 
32

 


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

 
Purchases
 
Sales
 
Net
   
Units
 
 
(In thousands)
 
Electricity Forwards
 
156
   
(2,913
)
 
(2,757
)
 
   MWH
 
Heating Oil Futures
 
5,880
   
-
   
5,880
   
   Gallons
 
Natural Gas Futures
 
3,000
   
(2,500
)
 
500
   
   mmBtu
 

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

Derivatives in Cash Flow Hedging Relationships
Electricity
   
Natural Gas
   
Heating Oil
       
       
Forwards
   
Futures
   
Futures
   
Total
 
Three Months Ended September 30, 2009
 
(in millions)
 
Gain (Loss) Recognized in AOCL (Effective Portion)
$
15
 
$
(2
)
$
-
 
$
13
 
Effective Gain (Loss) Reclassified to:(1)
                     
 
Purchased Power Expense
 
11
   
-
   
-
   
11
 
 
Fuel Expense
 
-
   
(4
)
 
(2
)
 
(6
)
                           
Nine Months Ended September 30, 2009
                       
Gain (Loss) Recognized in AOCL (Effective Portion)
$
19
 
$
(9
)
$
-
 
$
10
 
Effective Gain (Loss) Reclassified to:(1)
                       
 
Purchased Power Expense
 
(6
)
 
-
   
-
   
(6
)
 
Fuel Expense
 
-
   
(9
)
 
(10
)
 
(19
)
                           
                             
Three Months Ended September 30, 2008
                       
Gain (Loss) Recognized in AOCL (Effective Portion)
$
42
 
$
(2
)
$
-
 
$
40
 
Effective Gain (Loss) Reclassified to:(1)
                     
 
Purchased Power Expense
 
3
   
-
   
-
   
3
 
 
Fuel Expense
 
-
   
3
   
-
   
3
 
                           
Nine Months Ended September 30, 2008
                       
Gain (Loss) Recognized in AOCL (Effective Portion)
$
12
 
$
4
 
$
-
 
$
16
 
Effective Gain (Loss) Reclassified to:(1)
                       
 
Purchased Power Expense
 
(10
)
 
-
   
-
   
(10
)
 
Fuel Expense
 
-
   
4
   
-
   
4
 
                           
(1) The ineffective portion was immaterial.
                       

   
Three Months Ended September 30
   
Nine Months Ended September 30
 
Derivatives Not in Hedging Relationships
   
NUG
                 
NUG
             
     
Contracts
   
Other
   
Total
     
Contracts
   
Other
   
Total
 
2009
 
(In millions)
 
Unrealized Gain (Loss) Recognized in:
                                       
Fuel Expense(1)
 
$
-
 
$
(1
)
$
(1
)
 
$
-
 
$
2
 
$
2
 
Regulatory Assets(2)
   
(22
)
 
-
   
(22
)
   
(406
)
 
-
   
(406
)
   
$
(22
)
$
(1
)
$
(23
)
 
$
(406
)
$
2
 
$
(404
)
Realized Gain (Loss) Reclassified to:
                                       
Fuel Expense(1)
 
$
-
 
$
1
 
$
1
   
$
-
 
$
-
 
$
-
 
Regulatory Assets(2)
   
(93
)
 
-
   
(93
)
   
(273
)
 
11
   
(262
)
   
$
(93
)
$
1
 
$
(92
)
 
$
(273
)
$
11
 
$
(262
)
2008
                                       
Unrealized Gain (Loss) Recognized in:
                                       
Fuel Expense(1)
 
$
-
 
$
2
 
$
2
   
$
-
 
$
2
 
$
2
 
Regulatory Assets(2)
   
(362
)
 
1
   
(361
)
   
314
   
1
   
315
 
   
$
(362
)
$
3
 
$
(359
)
 
$
314
 
$
3
 
$
317
 
Realized Gain (Loss) Reclassified to:
                                       
Fuel Expense(1)
 
$
-
 
$
1
 
$
1
   
$
-
 
$
1
 
$
1
 
Regulatory Assets(2)
   
(57
)
 
1
   
(56
)
   
(167
)
 
11
   
(156
)
   
$
(57
)
$
2
 
$
(55
)
 
$
(167
)
$
12
 
$
(155
)
     
(1) The realized gain (loss) is reclassified upon termination of the derivative instrument.  
(2) Changes in the fair value of NUG contracts are deferred for future recovery from (or refund to) customers.  


 
33

 

Total unamortized losses included in AOCL associated with commodity derivatives were $9 million ($5 million net of tax) as of September 30, 2009, as compared to $44 million ($27 million net of tax) as of December 31, 2008. The net of tax change resulted from a net $7 million decrease related to current hedging activity and a $15 million decrease due to net hedge losses reclassified to earnings during the first nine months of 2009. Based on current estimates, approximately $3 million (after tax) of the net deferred losses on derivative instruments in AOCL as of September 30, 2009 are expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuate from period to period based on various market factors.

Many of FirstEnergy’s commodity derivatives contain credit risk features. As of September 30, 2009, FirstEnergy posted $133 million of collateral related to net liability positions and held no counterparties’ funds related to asset positions. The collateral FirstEnergy has posted relates to both derivative and non-derivative contracts. FirstEnergy’s largest derivative counterparties fully collateralize all derivative transactions. Certain commodity derivative contracts include credit risk-related contingent features that would require FirstEnergy to post additional collateral if the credit rating for its debt were to fall below investment grade. The aggregate fair value of derivative instruments with credit risk-related contingent features that are in a liability position on September 30, 2009 was $2 million, for which $106 million in collateral has been posted. If FirstEnergy’s credit rating were to fall below investment grade, it would be required to post $18 million of additional collateral related to commodity derivatives.

6. PENSION AND OTHER POSTRETIREMENT BENEFITS

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

On June 2, 2009, FirstEnergy amended its health care benefits plan (Plan) for all employees and retirees eligible to participate in the Plan. The Plan amendment, which reduces future health care coverage subsidies paid by FirstEnergy on behalf of participants, triggered a remeasurement of FirstEnergy’s other postretirement benefit plans as of May 31, 2009. As a result of the remeasurement, the Plan’s discount rate was revised to 7.5% while the expected long-term rate of return on assets remained at 9%. The remeasurement and Plan amendment increased FirstEnergy’s AOCI by approximately $449 million ($252 million, net of tax) in the second quarter of 2009 and reduced FirstEnergy’s 2009 net postretirement benefit cost (including amounts capitalized) by $48 million, including $27 million applicable to the first nine months of 2009.

 
In the third quarter of 2009, FirstEnergy incurred a $13 million net postretirement benefit cost (including amounts capitalized) related to an additional liability created by the VERO offered by FirstEnergy to qualified employees. The special termination benefits of the VERO included additional health care coverage subsidies paid by FirstEnergy to those qualified employees who elected to retire. A total of 715 employees accepted the VERO.

On September 2, 2009, the Utilities and ATSI made a $500 million voluntary contribution to the FirstEnergy Corp. Pension Plan (Pension Plan). Due to the significance of the voluntary contribution, FirstEnergy elected to remeasure its Pension Plan as of August 31, 2009. As a result of the remeasurement, the Pension Plan’s discount rate was revised to 6% while the expected long-term rate of return on assets remained at 9%. The remeasurement and voluntary contribution decreased FirstEnergy’s AOCI by approximately $494 million ($304 million, net of tax) in the third quarter of 2009 and will reduce FirstEnergy’s net postretirement benefit cost (including amounts capitalized) for the remainder of 2009 by $7 million, including a $2 million reduction that is applicable to the third quarter of 2009.

FirstEnergy’s net pension and OPEB expenses (benefits) for the three months ended September 30, 2009 and 2008 were $36 million (including $9 million attributable to the VERO-related charge mentioned above), and $(15) million, respectively. For the nine months ended September 30, 2009 and 2008, FirstEnergy’s net pension and OPEB expenses (benefits) were $117 million and $(44) million, respectively. The components of FirstEnergy's net pension and other postretirement benefit costs (including amounts capitalized) for the three months and nine months ended September 30, 2009 and 2008, consisted of the following:

 
34

 


   
Three Months Ended
 
Nine Months Ended
 
   
September 30
 
September 30
 
Pension Benefits
 
2009
 
2008
 
2009
 
2008
 
   
(In millions)
 
Service cost
 
$
23
 
$
22
 
$
66
 
$
65
 
Interest cost
   
79
   
75
   
239
   
224
 
Expected return on plan assets
   
(86
)
 
(116
)
 
(248
)
 
(347
)
Amortization of prior service cost
   
3
   
3
   
10
   
10
 
Recognized net actuarial loss
   
45
   
2
   
129
   
6
 
Net periodic cost (credit)
 
$
64
 
$
(14
)
$
196
 
$
(42
)


   
Three Months Ended
 
Nine Months Ended
 
   
September 30
 
September 30
 
Other Postretirement Benefits
 
2009
 
2008
 
2009
 
2008
 
   
(In millions)
 
Service cost
 
$
15
 
$
5
 
$
23
 
$
14
 
Interest cost
   
13
   
18
   
51
   
55
 
Expected return on plan assets
   
(9
)
 
(13
)
 
(27
)
 
(38
)
Amortization of prior service cost
   
(48
)
 
(37
)
 
(127
)
 
(111
)
Recognized net actuarial loss
   
15
   
12
   
46
   
35
 
Net periodic cost (credit)
 
$
(14
)
$
(15
)
$
(34
)
$
(45
)

Pension and postretirement benefit obligations are allocated to FirstEnergy's subsidiaries employing the plan participants. FES and the Utilities capitalize employee benefits related to construction projects. The net periodic pension costs and net periodic postretirement benefit costs (including amounts capitalized) recognized by FES and each of the Utilities for the three months and nine months ended September 30, 2009 and 2008 were as follows:

   
Three Months Ended
 
Nine Months Ended
 
   
September 30
 
September 30
 
Pension Benefit Cost (Credit)
 
2009
 
2008
 
2009
 
2008
 
   
(In millions)
 
FES
 
$
19
 
$
5
 
$
56
 
$
16
 
OE
   
6
   
(6
)
 
20
   
(18
)
CEI
   
5
   
(1
)
 
14
   
(3
)
TE
   
2
   
(1
)
 
5
   
(2
)
JCP&L
   
8
   
(3
)
 
26
   
(10
)
Met-Ed
   
5
   
(2
)
 
16
   
(7
)
Penelec
   
4
   
(3
)
 
13
   
(9
)
Other FirstEnergy subsidiaries
   
15
   
(3
)
 
46
   
(9
)
   
$
64
 
$
(14
)
$
196
 
$
(42
)


   
Three Months Ended
 
Nine Months Ended
 
   
September 30
 
September 30
 
Other Postretirement Benefit Cost (Credit)
 
2009
 
2008
 
2009
 
2008
 
   
(In millions)
 
FES
 
$
(4
)
$
(2
)
$
(8
)
$
(5
)
OE
   
(3
)
 
(2
)
 
(8
)
 
(5
)
CEI
   
-
   
1
   
1
   
2
 
TE
   
1
   
1
   
2
   
3
 
JCP&L
   
(2
)
 
(4
)
 
(4
)
 
(12
)
Met-Ed
   
(1
)
 
(3
)
 
(3
)
 
(8
)
Penelec
   
(1
)
 
(3
)
 
(2
)
 
(10
)
Other FirstEnergy subsidiaries
   
(4
)
 
(3
)
 
(12
)
 
(10
)
   
$
(14
)
$
(15
)
$
(34
)
$
(45
)


 
35

 

7. VARIABLE INTEREST ENTITIES

FirstEnergy and its subsidiaries consolidate VIEs when they are determined to be the VIE's primary beneficiary. FirstEnergy and its subsidiaries reflect the portion of VIEs not owned by them in the caption noncontrolling interest within the consolidated financial statements. The change in noncontrolling interest within the consolidated balance sheets is the result of net losses of the noncontrolling interests ($14 million), the acquisition of additional interest in certain joint ventures ($13 million), and distributions to owners ($4 million).

Mining Operations

On July 16, 2008, FEV entered into a joint venture with the Boich Companies, a Columbus, Ohio-based coal company, to acquire a majority stake in the Signal Peak mining and coal transportation operations near Roundup, Montana. FEV made a $125 million equity investment in the joint venture, which acquired 80% of the mining operations (Signal Peak Energy, LLC) and 100% of the transportation operations, with FEV owning a 45% economic interest and an affiliate of the Boich Companies owning a 55% economic interest in the joint venture. Both parties have a 50% voting interest in the joint venture. In March 2009, FEV agreed to pay a total of $8.5 million to affiliates of the Boich Companies to purchase an additional 5% economic interest in the Signal Peak mining and coal transportation operations. Voting interests remained unchanged after the sale was completed in July 2009. Effective August 21, 2009, the joint venture acquired the remaining 20% stake in the mining operations by issuing a five-year note for $47.5 million. FEV consolidates the mining and transportation operations of this joint venture in its financial statements.

Trusts

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

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

Loss Contingencies

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

   
Maximum Exposure
 
Discounted Lease Payments, net(1)
 
Net Exposure
   
(In millions)
FES
 
$
1,371
 
$
1,193
 
$
178
OE
 
729
 
561
 
168
CEI(2)
 
670
 
74
 
596
TE(2)
 
670
 
383
 
287
 
 
(1)  
The net present value of FirstEnergy's consolidated sale and
leaseback operating lease commitments is $1.7 billion
 
(2)  
CEI and TE are jointly and severally liable for the maximum loss
amounts under certain sale-leaseback agreements.

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

 
36

 


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

Power Purchase Agreements

FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to the Utilities and the contract price for power is correlated with the plant's variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec, maintains 25 long-term power purchase agreements with NUG entities. The agreements were entered into pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.

FirstEnergy has determined that for all but eight of these entities, neither JCP&L, Met-Ed nor Penelec have variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of consolidation consideration for VIEs. 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. 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.

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 from those contracts to be recovered from customers. Purchased power costs from these entities during the three months and nine months ended September 30, 2009 and 2008 are shown in the following table:

   
Three Months Ended
 
Nine Months Ended
 
   
September 30
 
September 30
 
   
2009
 
2008
 
2009
 
2008
 
   
(In millions)
 
JCP&L
 
$
20
 
$
26
 
$
57
 
$
67
 
Met-Ed
   
11
   
12
   
39
   
44
 
Penelec
   
9
   
8
   
26
   
25
 
Total
 
$
40
 
$
46
 
$
122
 
$
136
 

 
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 September 30, 2009, $349 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.

 
37

 


8. INCOME TAXES

FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. Accounting guidance prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken on a company's tax return. Upon completion of the federal tax examination for the 2007 tax year in the first quarter of 2009, FirstEnergy recognized $13 million in tax benefits, which favorably affected FirstEnergy's effective tax rate. Material changes to FirstEnergy's unrecognized tax benefits during the third quarter of 2009 are described further below. Upon completion of the federal tax examinations for tax years 2004 to 2006 in the third quarter of 2008, FirstEnergy recognized approximately $45 million in tax benefits, including $5 million that favorably affected FirstEnergy’s effective tax rate. A majority of the tax benefits recognized in the third quarter of 2008 adjusted goodwill as a purchase accounting adjustment ($20 million) and accumulated deferred income taxes for temporary tax items ($15 million). As of September 30, 2009, FirstEnergy expects that $197 million of unrecognized benefits will be resolved within the next twelve months, of which approximately $148 million, if recognized, would affect FirstEnergy's effective tax rate. The potential decrease in the amount of unrecognized tax benefits is primarily associated with issues related to the capitalization of certain costs, gains and losses recognized on the disposition of assets and various other tax items.

The Company recognizes 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 and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes. The reversal of accrued interest associated with the $45 million in recognized tax benefits in 2008 favorably affected FirstEnergy’s effective tax rate by $12 million in the third quarter and first nine months of 2008. During the first nine months of 2009, there were no material changes to the amount of interest accrued. The net amount of accumulated interest accrued as of September 30, 2009 was $67million, as compared to $59 million as of December 31, 2008.

In 2008, FirstEnergy, on behalf of FGCO and NGC, filed a change in accounting method related to the costs to repair and maintain electric generation stations. During the second quarter of 2009, the IRS approved the change in accounting method and $281 million of costs were included as a repair deduction in FirstEnergy’s 2008 consolidated tax return. Since the IRS did not complete its review over this change in accounting method by the extended filing date of FirstEnergy’s federal tax return, FirstEnergy increased the amount of unrecognized tax benefits by $34 million in the third quarter of 2009, with a corresponding adjustment to accumulated deferred income taxes for this temporary tax item. There was no impact on FirstEnergy’s effective tax rate for the quarter.

FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state tax authorities. All state jurisdictions are open from 2001-2008. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items are under appeal. The federal audits for the years 2004-2006 were completed in 2008 and several items are under appeal. The IRS began auditing the year 2007 in February 2007 under its Compliance Assurance Process program and was completed in the first quarter of 2009 with two items under appeal. The IRS began auditing the year 2008 in February 2008 and the year 2009 in February 2009 under its Compliance Assurance Process program. Neither audit is expected to close before December 2009. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy's financial condition or results of operations.

9. 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 September 30, 2009, outstanding guarantees and other assurances aggregated approximately $4.1 billion, consisting primarily of parental guarantees ($1 billion), subsidiaries’ guarantees ($2.6 billion), surety bonds ($0.1 billion) and LOCs ($0.4 billion).

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.4 billion (included in the $1 billion shown above) as of September 30, 2009 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.

 
38

 


While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of September 30, 2009, FirstEnergy's maximum exposure under these collateral provisions was $616 million, consisting of $53 million due to “material adverse event” contractual clauses and $563 million due to a below investment grade credit rating. Additionally, stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase this amount to $699 million, consisting of $60 million due to “material adverse event” contractual clauses and $639 million due to a below investment grade credit rating.

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $103 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

In addition to guarantees and surety bonds, FES’ contracts, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions which require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ contracts as of September 30, 2009, and forward prices as of that date, FES had $183 million of outstanding collateral payments of which $134 million is included in other assets on the Consolidated Balance Sheet as of September 30, 2009. Under a hypothetical adverse change in forward prices (15% decrease in the first 12 months and 20% decrease in prices thereafter), FES would be required to post an additional $45 million. Depending on the volume of forward contracts and future price movements, FES could be required to post significantly higher amounts for margining. In connection with FES’ obligations to post and maintain collateral under the two-year PSA entered into by FES and the Ohio Companies following the CBP auction on May 13-14, 2009, NGC entered into a Surplus Margin Guaranty in the amount of approximately $500 million. The surplus margin guaranty is secured by an NGC FMB issued in favor of the Ohio Companies.

In July 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has fully and irrevocably guaranteed all of FGCO’s obligations under each of the leases (see Note 13). 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.

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

(B)     ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergy with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FirstEnergy estimates capital expenditures for environmental compliance of approximately $800 million for the period 2009-2013.

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

FirstEnergy is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in the shutdown of the generating unit involved and/or civil or criminal penalties of up to $37,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. FirstEnergy believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

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

In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices or repowering and provides for stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree, including repowering Burger Units 4 and 5 for biomass fuel consumption, are currently estimated to be $706 million for 2009-2012 (with $414 million expected to be spent in 2009).

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. In July 2008, three additional complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the three complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. On October 14, 2008, the Court granted FGCO’s motion to consolidate discovery for all four complaints pending against the Bruce Mansfield Plant. On August 17, 2009, a settlement of the PennFuture complaint was reached with PennFuture and one of the three individual complainants. On October 16, 2009, the Court approved the settlement and dismissed the claims of PennFuture and of the settling individual complainant. The other two non-settling complainants are now represented by counsel handling the three cases filed in July 2008. FGCO believes those claims are without merit and intends to defend itself against the allegations made in those three complaints. The Pennsylvania Department of Health, under a Cooperative Agreement with the Agency for Toxic Substances and Disease Registry, completed a Health Consultation regarding the Mansfield Plant and issued a report dated March 31, 2009 which concluded there is insufficient sampling data to determine if any public health threat exists for area residents due to emissions from the Mansfield Plant. The report recommended additional air monitoring and sample analysis in the vicinity of the Mansfield Plant, which the Pennsylvania Department of Environmental Protection has completed.

On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. Specifically, Connecticut and New Jersey allege that "modifications" at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. On December 5, 2008, New Jersey filed an amended complaint, adding claims with respect to alleged modifications that occurred after GPU’s sale of the plant. Met-Ed filed a Motion to Dismiss the claims in New Jersey’s Amended Complaint and Connecticut’s Complaint on February 19, 2009, and on September 30, 2009, respectively. The Court granted Met-Ed's motion to dismiss New Jersey’s and Connecticut’s claims for injunctive relief against Met-Ed, but denied Met-Ed’s motion to dismiss the claims for civil penalties on statute of limitations grounds in order to allow the states to prove either that the application of the discovery rule or the doctrine of equitable tolling bars application of the statute of limitations.


 
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On January 14, 2009, the EPA issued a NOV to Reliant alleging new source review violations at the Portland Generation Station based on “modifications” dating back to 1986. Met-Ed is unable to predict the outcome of this matter. The EPA’s January 14, 2009, NOV also alleged new source review violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of the Keystone Station and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter.
 
On June 11, 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. alleging that "modifications" at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program. Mission Energy is seeking indemnification from Penelec, the co-owner (along with New York State Electric and Gas Company) and operator of the Homer City Power Station prior to its sale in 1999. The scope of Penelec’s indemnity obligation to and from Mission Energy is disputed. Penelec is unable to predict the outcome of this matter.

On May 16, 2008, FGCO received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an Administrative Consent Order modifying that request and setting forth a schedule for FGCO’s response. On October 27, 2008, FGCO received a second request from the EPA for information pursuant to Section 114(a) of the CAA for additional operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants. On August 12, 2009, the EPA issued a Finding of Violation and NOV alleging violations of the Clean Air Act and Ohio regulations, including the prevention of significant deterioration (“PSD”), non-attainment new source review (NNSR”), and Title V regulations at the Eastlake, Lakeshore, Bay Shore, and Ashtabula generating plants. The EPA’s NOV alleges equipment replacements occurring during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. On September 15, 2009, FGCO received an additional information request pursuant to Section 114(a) of the Clean Air Act requiring FirstEnergy to submit certain operating and maintenance information and planning information regarding the Eastlake, Lake Shore, Bay Shore and Ashtabula generating plants. On November 3, 2009, FGCO received a letter providing notification that the EPA is evaluating whether certain scheduled maintenance at the Eastlake generating plant may constitute a major modification under the NSR provision of the CAA. FGCO intends to comply with the CAA, including EPA’s information requests, but, at this time, is unable to predict the outcome of this matter. A June 15, 2006 finding of violation and NOV in which EPA alleged CAA violations at the Bay Shore Generating Plant remains unresolved and FGCO is unable to predict the outcome of such matter.

On August 18, 2008, FirstEnergy received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding its formerly-owned Avon Lake and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. FirstEnergy intends to fully comply with the EPA’s information request, but, at this time, is unable to predict the outcome of this matter.

National Ambient Air Quality Standards

In March 2005, the EPA finalized CAIR, covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia, based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR requires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOX emissions to 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. On December 23, 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s July 11, 2008 opinion. On July 10, 2009, the United States Court of Appeals for the District of Columbia ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOX SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the "8-hour" ozone NAAQS. FGCO's future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA in response to the Court’s ruling.


 
 
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Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the Court vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA petitioned for rehearing by the entire Court, which denied the petition on May 20, 2008. On October 17, 2008, the EPA (and an industry group) petitioned the United States Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the EPA moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the EPA’s petition and denied the industry group’s petition. On October 21, 2009, the EPA opened a 30-day comment period on a proposed consent decree that would obligate the EPA to propose maximum achievable control technology (MACT) regulations for mercury and other hazardous air pollutants by March 16, 2011, and to finalize the regulations by November 16, 2011.  FGCO’s future cost of compliance with MACT regulations may be substantial and will depend on the action taken by the EPA and on how any future regulations are ultimately implemented.

Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. On January 30, 2009, the Commonwealth Court of Pennsylvania declared Pennsylvania’s mercury rule “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule. It is anticipated that compliance with these regulations, if the Commonwealth Court’s rulings were reversed on appeal and Pennsylvania’s mercury rule was implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant (FirstEnergy’s only Pennsylvania coal-fired power plant) until 2015, if at all.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing, by 2012, the amount of man-made GHG, including CO2, emitted by developed countries. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. The EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity used in the United States comes from renewable sources by 2012, increasing to 25% by 2025, and implementing an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050.

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the House of Representatives passed one such bill, the American Clean Energy and Security Act of 2009, on June 26, 2009. The Senate continues to consider a number of measures to regulate GHG emissions. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. On April 17, 2009, the EPA released a “Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s proposed finding concludes that the atmospheric concentrations of several key greenhouse gases threaten the health and welfare of future generations and that the combined emissions of these gases by motor vehicles contribute to the atmospheric concentrations of these key greenhouse gases and hence to the threat of climate change. Although the EPA’s proposed finding, if finalized, does not establish emission requirements for motor vehicles, such requirements would be expected to occur through further rulemakings. Additionally, while the EPA’s proposed findings do not specifically address stationary sources, including electric generating plants, those findings, if finalized, would be expected to support the establishment of future emission requirements by the EPA for stationary sources. On September 23, 2009, the EPA finalized a GHG reporting rule establishing a national GHG emissions collection and reporting program. The EPA rules will require FirstEnergy to measure GHG emissions commencing in 2010 and submit reports commencing in 2011. On September 30, 2009, EPA proposed new thresholds for GHG emissions that define when Clean Air Act permits under the New Source Review and Title V operating permits programs would be required. EPA is proposing a major source emissions applicability threshold of 25,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) for existing facilities under the Title V operating permits program and the Prevention of Significant Determination (PSD) portion of NSR. EPA is also proposing a significance level between 10,000 and 25,000 tpy CO2e to determine if existing major sources making modifications that result in an increase of emissions above the significance level would be required to obtain a PSD permit.


 
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On September 21, 2009, the U.S. Court of Appeals for the Second Circuit and on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit, reversed and remanded lower court decisions that had dismissed complaints alleging damage from GHG emissions on jurisdictional grounds.  These cases involve common law tort claims, including public and private nuisance, alleging that GHG emissions contribute to global warming and result in property damages.   Connecticut v. AEP, No. 05-5105-cv (2d Cir. 2009)(seeking injunctive relief only); Comer v. Murphy Oil USA, No. 07-6-756 (5th Cir. 2009)(seeking damages only), respectively.  While FirstEnergy is not a party to either litigation, should the courts of appeals decisions be affirmed, FirstEnergy and/or one or more of its subsidiaries could be named in actions making similar allegations.
 
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.

Clean Water Act

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

On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 1, 2009, the Supreme Court of the United States reversed one significant aspect of the Second Circuit Court’s opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. EPA is developing a new regulation under Section 316(b) of the Clean Water Act consistent with the opinions of the Supreme Court and the Court of Appeals which have created significant uncertainty about the specific nature, scope and timing of the final performance standard. FirstEnergy is studying various control options and their costs and effectiveness. Depending on the results of such studies and the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

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

As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate non-hazardous waste. In February 2009, the EPA requested comments from the states on options for regulating coal combustion wastes, including regulation as non-hazardous waste or regulation as a hazardous waste. In March and June 2009, the EPA requested information from FGCO’s Bruce Mansfield Plant regarding the management of coal combustion wastes. The EPA is reviewing its previous determination that Federal regulation of coal ash as a hazardous waste is not appropriate. The EPA has indicated an intent to propose regulations regarding this issue by the end of the year. Additional regulations of fossil-fuel combustion waste products could have a significant impact on our management, beneficial use, and disposal, of coal ash. FGCO's future cost of compliance with any coal combustion waste regulations which may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the states.


 
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The Utilities have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the consolidated balance sheet as of September 30, 2009, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $104 million (JCP&L - $77 million, TE - $1 million, CEI - $1 million, FGCO - $1 million and FirstEnergy - $24 million) have been accrued through September 30, 2009. Included in the total are accrued liabilities of approximately $68 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

(C)    OTHER LEGAL PROCEEDINGS

Other Legal Proceedings

Power Outages and Related Litigation

In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages due to the outages.

After various motions, rulings and appeals, the Plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability, and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. The class was decertified twice by the trial court, and appealed both times by the Plaintiffs, with the results being that: (1) the Appellate Division limited the class only to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation which resulted in planned and unplanned outages in the area during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. On March 31, 2009, the trial court again granted JCP&L’s motion to decertify the class. On April 20, 2009, the Plaintiffs filed a motion for leave to take an interlocutory appeal to the trial court's decision to decertify the class, which was granted by the Appellate Division on June 15, 2009. Plaintiffs filed their appellate brief on August 25, 2009, and JCP&L filed an opposition brief on September 25, 2009. On or about October 13, 2009, Plaintiffs filed their reply brief in further support of their appeal of the trial court's decision decertifying the class. The Appellate Division has scheduled oral argument for January 5, 2010..

Nuclear Plant Matters

In August 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. On November 5, 2009, the NRC issued a renewed operating license for Beaver Valley Power Station, Units 1 and 2. The operating licenses for these facilities was extended until 2036 and 2047 for Units 1 and 2, respectively.

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of September 30, 2009, FirstEnergy had approximately $1.9 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry, and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy provided an additional $80 million parental guarantee associated with the funding of decommissioning costs for these units and indicated that it planned to contribute an additional $80 million to these trusts by 2010. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s obligations to fund the trusts may increase. The recent disruption in the capital markets and its effects on particular businesses and the economy in general also affects the values of the nuclear decommission trusts. On June 18, 2009, the NRC informed FENOC that its review tentatively concluded that a shortfall ($147.5 million net present value) existed in the value of the decommissioning trust fund for Beaver Valley Unit 1. On July 28, 2009, FENOC submitted a letter to the NRC that stated reasonable assurance of decommissioning funding is provided for Beaver Valley Unit 1 through a combination of the existing trust fund balances, the existing $80 million parental guarantee from FirstEnergy and maintaining the plant in a safe-store configuration, or extended safe shutdown condition, after plant shutdown. On October 20, 2009, FENOC received a request for additional information (RAI) from the NRC that questions FENOC's methodology for calculating the decommissioning obligations for Beaver Valley Unit 1. Renewal of the operating license for Beaver Valley Unit 1 is expected to mitigate the estimated shortfall in the unit’s nuclear decommissioning funding status. FENOC continues to communicate with the NRC regarding future actions to provide reasonable assurance for decommissioning funding. Such actions may include additional parental guarantees or contributions to those funds.


 
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Other Legal Matters

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

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. A final order identifying the individual damage amounts was issued on October 31, 2007 and the award appeal process was initiated. The union filed a motion with the federal Court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. On February 25, 2009, the federal district court denied JCP&L’s motion to vacate the arbitration decision and granted the union’s motion to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009. The appeal process could take as long as 24 months. The parties are participating in the federal court's mediation programs and have held private settlement discussions. JCP&L recognized a liability for the potential $16 million award in 2005. Post-judgment interest began to accrue as of February 25, 2009, and the liability will be adjusted accordingly.

The bargaining unit employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. On July 24, 2009, FirstEnergy declared that bargaining was at an impasse and portions of its last contract offer were implemented August 1, 2009, and a voluntary retirement program was implemented on August 19, 2009.  A federal mediator is continuing to assist the parties in reaching a negotiated contract settlement. FirstEnergy has a strike mitigation plan ready in the event of a strike.

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.

10. REGULATORY MATTERS

(A)    RELIABILITY INITIATIVES

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

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

In April 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the MISO region and found it to be in full compliance with all audited reliability standards. Similarly, in October 2008, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the PJM region and found it to be in full compliance with all audited reliability standards.

On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations, with customers in the affected area losing power. Power was restored to most customers within a few hours and to all customers within eleven hours. On December 16, 2008, JCP&L provided preliminary information about the event to certain regulatory agencies, including the NERC. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. The initial phase of the investigation required JCP&L to respond to the NERC’s request for factual data about the outage. JCP&L submitted its written response on May 1, 2009. The NERC conducted on site interviews with personnel involved in responding to the event on June 16-17, 2009. On July 7, 2009, the NERC issued additional questions regarding the event and JCP&L replied as requested on August 6, 2009. JCP&L is not able at this time to predict what actions, if any, that the NERC may take based on the data submittals or interview results.

 
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On June 5, 2009, FirstEnergy self-reported to ReliabilityFirst a potential violation of NERC Standard PRC-005 resulting from its inability to validate maintenance records for 20 protection system relays in JCP&L’s and Penelec’s transmission systems. These potential violations were discovered during a comprehensive field review of all FirstEnergy substations to verify equipment and maintenance database accuracy. FirstEnergy has completed all mitigation actions, including calibrations and maintenance records for the relays. ReliabilityFirst issued an Initial Notice of Alleged Violation on June 22, 2009. The NERC approved FirstEnergy’s mitigation plan on August 19, 2009, and submitted it to the FERC for approval on August 19, 2009. FirstEnergy is not able at this time to predict what actions or penalties, if any, that ReliabilityFirst will propose for this self-report of violation.

(B)    OHIO

On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing to support a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of its investigation into the distribution rate request. On January 21, 2009, the PUCO granted the Ohio Companies’ application to increase electric distribution rates by $136.6 million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million). These increases went into effect for OE and TE on January 23, 2009, and for CEI on May 1, 2009. Applications for rehearing of this order were filed by the Ohio Companies and one other party on February 20, 2009. The PUCO granted these applications for rehearing on March 18, 2009 for the purpose of further consideration. The PUCO has not yet issued a substantive Entry on Rehearing.

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

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

 
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On July 27, 2009, the Ohio Companies filed applications with the PUCO to recover three different categories of deferred distribution costs on an accelerated basis. In the Ohio Companies' Amended ESP, the PUCO approved the recovery of these deferrals, with collection originally set to begin in January 2011 and to continue over a 5 or 25 year period. The principal amount plus carrying charges through August 31, 2009 for these deferrals was a total of $305.1 million. The applications were approved by the PUCO on August 19, 2009. Recovery of this amount, together with carrying charges calculated as approved in the Amended ESP, commenced on September 1, 2009, and will be collected in the 18 non-summer months from September 2009 through May 2011, subject to reconciliation until fully collected, with $165 million of the above amount being recovered from residential customers, and $140.1 million being recovered from non-residential customers.

The CBP auction occurred on May 13-14, 2009, and resulted in a weighted average wholesale price for generation and transmission of 6.15 cents per KWH. The bid was for a single, two-year product for the service period from June 1, 2009 through May 31, 2011. FES participated in the auction, winning 51% of the tranches (one tranche equals one percent of the load supply). Subsequent to the signing of the wholesale contracts, three winning bidders reached separate agreements with FES to assign a total of 21 tranches to FES for various periods. The results of the CBP were accepted by the PUCO on May 14, 2009. In addition, FES has separately contracted with numerous communities to provide retail generation service through governmental aggregation programs.

SB221 also requires electric distribution utilities to implement energy efficiency programs. Under the provisions of SB221, the Ohio Companies are required to achieve a total annual energy savings equivalent of approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013, with additional savings required through 2025. Utilities are also required to reduce peak demand in 2009 by 1%, with an additional seventy-five hundredths of one percent reduction each year thereafter through 2018. The PUCO may amend these benchmarks in certain, limited circumstances. Additionally, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they serve in 2009. The Ohio Companies are presently involved in collaborative efforts related to energy efficiency, including filing applications for approval with the PUCO, as well as other implementation efforts arising out of the Supplemental Stipulation. We expect that all costs associated with compliance will be recoverable from customers.

On June 17, 2009, the PUCO modified rules that implement the alternative energy portfolio standards created by SB221, including the incorporation of energy efficiency requirements, long-term forecast and greenhouse gas reporting and CO2 control planning. The PUCO filed the rules with the Joint Committee on Agency Rule Review (JCARR) on July 7, 2009, after which began a 65-day review period. On August 6, 2009, the PUCO withdrew alternative energy and energy efficiency/peak demand reduction rules from JCARR. On August 24, 2009, the integrated resource planning rules were also withdrawn from JCARR. The Ohio Companies and one other party filed applications for rehearing on the rules with the PUCO on July 17, 2009. On August 11, 2009, the PUCO issued an entry on rehearing granting the applications for rehearing only for purposes of further consideration of the issues raised.

On October 15, 2009, the PUCO issued a second Entry on Rehearing, modifying certain of its previous rules. Modified rules previously withdrawn from JCARR were refiled with JCARR on October 16 and October 19, 2009. The rules set out the manner in which the electric utilities, including the Ohio companies, will be required to comply with benchmarks contained in SB 221 related to the employment of alternative energy resources, energy efficiency/peak demand reduction programs as well as greenhouse gas reporting requirements and changes to long term forecast reporting requirements. The rules severely restrict the types of renewable energy resources and energy efficiency and peak reduction programs that may be included toward meeting the statutory goals, which is expected to significantly increase the cost of compliance for the Ohio Companies' customers. On October 23, 2009, the rules were placed in a “to be re-filed” status by JCARR. It is currently unclear what form the final rules may take or their potential impact on the Ohio Companies. As a result of this uncertainty surrounding the rules, as well as the Commission’s failure to address certain energy efficiency applications submitted by the Ohio Companies throughout the year and the Commission’s recent directive to postpone the launch of a Commission-approved energy efficiency program, the Ohio Companies, on October 27, 2009, submitted an application to amend their 2009 statutory energy efficiency benchmarks to zero. Absent this regulatory relief the Ohio Companies may not be able to meet their 2009 statutory energy efficiency benchmarks, which may result in the assessment of a forfeiture by the PUCO. The Ohio Companies asked the Commission to issue a ruling on or before December 2, 2009.

In August and October 2009, the Ohio Companies conducted RFPs to secure Renewable Energy Credits (RECs). The RFPs includes solar and other renewable energy RECs, including those generated in Ohio. The RECs from these two RFPs will be used to help meet the renewable energy requirements established under Senate Bill 221 for 2009, 2010, and 2011.

 
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On October 20, 2009, the Ohio Companies filed an MRO to procure electric generation service for the period beginning June 1, 2011. The proposed MRO would establish a CBP to secure generation supply for customers who do not shop with an alternative supplier and would be similar, in all material respects, to the CBP conducted in May 2009 in that it would procure energy, capacity and certain transmission services on a slice of system basis. However, unlike the May 2009 CBP, the MRO would include multiple bidding sessions and multiple products with different delivery periods for generation supply designed to reduce potential volatility, reduce supplier risk and encourage bidder participation. A technical conference was held on October 29, 2009, at the PUCO. Pursuant to SB221, the PUCO has 90 days to determine whether the MRO meets certain statutory requirements, therefore, the Ohio Companies have requested a PUCO determination by January 18, 2020. Under a determination that such statutory requirements were met, the Ohio Companies would be able to implement the MRO and conduct the CBP

(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.

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. The TSCs included a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010. Various interveners filed complaints against those filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing Met-Ed to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted. Hearings and briefing for both Met-Ed and Penelec have concluded. On August 11, 2009, the ALJ issued a Recommended Decision to the PPUC approving Met-Ed’s and Penelec’s TSCs as filed and dismissing all complaints. Exceptions by various interveners were filed and reply exceptions were filed by Met-Ed and Penelec. The Companies are now awaiting a PPUC decision.

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

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

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

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

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

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

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

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

 
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Act 129 requires utilities to file with the PPUC, an energy efficiency and peak load reduction plan by July 1, 2009. On January 15, 2009, in compliance with Act 129, the PPUC issued its proposed guidelines for the filing of utilities’ energy efficiency and peak load reduction plans. On July 1, 2009, Met-Ed, Penelec, and Penn filed EE&C Plans with the PPUC in accordance with Act 129. The Pennsylvania Companies submitted a supplemental filing on July 31, 2009, to revise the Total Resource Cost test items in the EE&C Plans pursuant to the PPUC’s June 23, 2009 Order. Following an evidentiary hearing and briefing, the Companies filed revised EE&C Plans on September 21, 2009. In an Order entered October 28, 2009, the PPUC approved, in part, and rejected, in part, the Pennsylvania Companies' filing. The Companies must file revised EE&C plans by December 28, 2009, incorporating minor revisions required by the PPUC.  These revisions are not expected to impose any additional financial obligations on the Pennsylvania Companies.

Act 129 also requires utilities to file with the PPUC a smart meter technology procurement and installation plan by August 14, 2009. On June 18, 2009, the PPUC issued its guidelines related to Smart Meter deployment. On August 14, 2009, Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation Plan as required by Act 129. A litigation schedule has been adopted which includes a Technical Conference and evidentiary hearings this fall. The Pennsylvania Companies expect the PPUC to act on the plans early next year.

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

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

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

On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance filing to the PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the residential class with a corresponding increase in the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $59 million), overall rates would remain unchanged. On July 30, 2009, the PPUC entered an order approving the 5-year NUG Statement, approving the reduction of the CTC, and directing Met-Ed and Penelec to file a tariff supplement implementing this change. On July 31, 2009, Met-Ed and Penelec filed tariff supplements decreasing the CTC rate in compliance with the July 30, 2009 order, and increasing the generation rate in compliance with the companies’ Restructuring Orders of 1998. On August 14, 2009, the PPUC issued Secretarial Letters approving Met-Ed and Penelec’s compliance filings. By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30 day comment period on whether “the Restructuring Settlement allows NUG over collection for select and isolated months to be used to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists.”   In response to the Tentative Order comments were filed by the Office of Small Business Advocate, Office of Consumer Advocate, York County Solid Waste and Refuse Authority, ARIPPA, the Met-Ed Industrial Users Group and Penelec Industrial Customer Alliance objecting to the above accounting method utilized by Met-Ed and Penelec. The Companies filed reply comments on October 26, 2009, and await the decision of the PPUC.
 
(D)    NEW JERSEY

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of September 30, 2009, the accumulated deferred cost balance totaled approximately $102 million.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004, supporting continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DPA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set. On March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009. This matter is currently pending before the NJBPU.

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

The EMP was issued on October 22, 2008, establishing five major goals:

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

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

·  
meet 30% of the state’s electricity needs with renewable energy by 2020;

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

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

On January 28, 2009, the NJBPU adopted an order establishing the general process and contents of specific EMP plans that must be filed by New Jersey electric and gas utilities in order to achieve the goals of the EMP. Such utility specific plans are due to be filed with the BPU by July 1, 2010. At this time, FirstEnergy and JCP&L cannot determine the impact, if any, the EMP may have on their operations.

In support of the New Jersey Governor's Economic Assistance and Recovery Plan, JCP&L announced a proposal to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. Under the proposal, an estimated $40 million would be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations. In addition, approximately $34 million would be spent implementing new demand response programs as well as expanding on existing programs. Another $11 million would be spent on energy efficiency, specifically replacing transformers and capacitor control systems and installing new LED street lights. The remaining $13 million would be spent on energy efficiency programs that would complement those currently being offered. The project relating to expansion of the existing demand response programs was approved by the BPU on August 19, 2009, and implementation will begin in 2009. Implementation of the remaining projects is dependent upon resolution of regulatory issues including recovery of the costs associated with the proposal.

(E)    FERC MATTERS

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or SECA) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order is pending before the FERC, and in the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements. On October 29, 2009, FirstEnergy and Exelon filed an additional settlement agreement with FERC to resolve their outstanding claims. FirstEnergy is actively pursuing settlement agreements with other parties to the case.

 
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PJM Transmission Rate

On January 31, 2005, certain PJM transmission owners made filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design, notably AEP, which proposed to create a "postage stamp," or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. AEP's proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order ("Opinion 494") finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.

On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. On February 11, 2008, AEP appealed the FERC’s April 19, 2007, and January 31, 2008, orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit. Oral arguments were held on April 13, 2009. The Seventh Circuit Court of Appeals issued a decision on August 6, 2009, that remanded the rate design to FERC and denied AEP’s appeal. A request for rehearing and rehearing en banc by Baltimore Gas & Electric and Old Dominion Electric Cooperative was denied by the Seventh Circuit on October 20, 2009. On October 28, 2009, the Seventh Circuit closed its case dockets and returned the case to FERC for further action on the remand order.

The FERC’s orders on PJM rate design prevented 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 reduces the cost of future transmission to be recovered from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding Judge to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement subject to the submission of a compliance filing. The compliance filing was submitted on August 29, 2008, and the FERC issued an order accepting the compliance filing on October 15, 2008. On November 14, 2008, PJM submitted revisions to its tariff to incorporate cost responsibility assignments for below 500 kV upgrades included in PJM’s Regional Transmission Expansion Planning process in accordance with the settlement. The FERC conditionally accepted the compliance filing on January 28, 2009. PJM submitted a further compliance filing on March 2, 2009, which was accepted by the FERC on April 10, 2009. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. An initial decision was issued by the Presiding Judge on September 18, 2008. PJM and FERC trial staff each filed a Brief on Exceptions to the initial decision on October 20, 2008. Briefs Opposing Exceptions were filed on November 10, 2008.

Post Transition Period Rate Design

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

 
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On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have the FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “Super Region” that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers. Lower voltage facilities would continue to be recovered in the local utility transmission rate zone through a license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On January 31, 2008, the FERC issued an order denying the complaint. The effect of this order is to prevent the shift of significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP was denied by the FERC on December 19, 2008. On February 17, 2009, AEP appealed the FERC’s January 31, 2008, and December 19, 2008, orders to the U.S. Court of Appeals for the Seventh Circuit. FESC, on behalf of its affiliated operating utility companies, filed a motion to intervene on March 10, 2009. The Seventh Circuit Court of Appeals has held this appeal in abeyance pending resolution of the Opinion 494 appeal discussed above. Now that the Seventh Circuit has ruled on the Opinion 494 case, AEP and FERC have until November 11, 2009, to advise the Seventh Circuit of any changes to their litigation positions that result from or reflect the Seventh Circuit’s decision in the Opinion 494 case.

RTO Consolidation

On August 17, 2009, FirstEnergy filed an application with the FERC requesting to consolidate its transmission assets and operations into PJM. Currently, FirstEnergy’s transmission assets and operations are divided between PJM and MISO. The consolidation would make the transmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. Most of FirstEnergy’s transmission assets in Pennsylvania and all of the transmission assets in New Jersey already operate as a part of PJM.

To ensure a definitive ruling at the same time FERC rules on its request to integrate ATSI into PJM, on October 19, 2009, FirstEnergy filed a related complaint with FERC on the issue of allocating transmission costs to the ATSI footprint for high voltage transmission projects approved prior to FirstEnergy’s integration into PJM.

FirstEnergy has requested that FERC rule on its application and the related complaint by December 17, 2009, to provide time to permit management to make a decision on whether to integrate ATSI into PJM prior to the 2010 Base Residual Auction for capacity. Subject to a satisfactory FERC ruling, the integration is expected to be complete on June 1, 2011, to coincide with delivery of power under the next competitive generation procurement process for FirstEnergy's Ohio companies.

On September 4, 2009, the PUCO opened a case to take comments from Ohio’s stakeholders regarding the RTO consolidation. FirstEnergy filed extensive comments in the PUCO case on September 25, 2009, and reply comments on October 13, 2009, and attended a public meeting on September 15, 2009 to answer questions regarding the RTO consolidation.

Several parties have intervened in the regulatory dockets at the FERC and at the PUCO. Certain interveners have commented and protested particular elements of the proposed RTO consolidation, including an exit fee to MISO, integration costs to PJM, and cost-allocations of future transmission upgrades in PJM and MISO. The result of these comments and protests could delay or otherwise have a material financial effect on the proposed RTO consolidation.

Changes ordered for PJM Reliability Pricing Model (RPM) Auction

On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act. On September 19, 2008, the FERC denied the RPM Buyers’ complaint. The FERC also ordered PJM to file on or before December 15, 2008, a report on potential adjustments to the RPM program as suggested in a Brattle Group report. On December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the RPM program. PJM also requested that the FERC conduct a settlement hearing to address changes to the RPM and suggested that the FERC should rule on the tariff amendments only if settlement could not be reached in January, 2009. The request for settlement hearings was granted. Settlement had not been reached by January 9, 2009 and, accordingly, FirstEnergy and other parties submitted comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief Judge issued an order terminating settlement discussions. On February 9, 2009, PJM and a group of stakeholders submitted an offer of settlement, which used the PJM December 12, 2008 filing as its starting point, and stated that unless otherwise specified, provisions filed by PJM on December 12, 2008, apply.

 
52

 

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

PJM has reconvened the Capacity Market Evolution Committee (CMEC) and has scheduled a CMEC Long-Term Issues Symposium to address near-term changes directed by the March 26, 2009 Order and other long-term issues not addressed in the February 2009 settlement. PJM made a compliance filing on September 1, 2009, incorporating tariff changes directed by the March 26, 2009 Order. The tariff changes were approved by the FERC in an order issued on October 30, 2009, and are effective November 1, 2009. The CMEC continues to work to address additional compliance items directed by the March 26, 2009 Order. Another compliance filing is due December 1, 2009.

MISO Resource Adequacy Proposal

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

On October 20, 2008, the FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a compliance filing modifying the cost of new entry penalty. Second, the FERC conditionally accepted MISO's compliance filing on the qualifications for purchased power agreements to be capacity resources, load forecasting, loss of load expectation, and planning reserve zones. Additional compliance filings were directed on accreditation of load modifying resources and price responsive demand. Finally, the FERC largely denied rehearing of its March 26 order with the exception of issues related to behind the meter resources and certain ministerial matters. On November 19, 2008, MISO made various compliance filings pursuant to these orders. Issuance of orders on rehearing and two of the compliance filings occurred on February 19, 2009. No material changes were made to MISO’s Resource Adequacy program. On April 16, 2009, the FERC issued an additional order on rehearing and compliance, approving MISO’s proposed financial settlement provision for Resource Adequacy. The MISO Resource Adequacy process was implemented as planned on June 1, 2009, the beginning of the MISO planning year. On June 17, 2009, MISO submitted a compliance filing in response to the FERC’s April 16, 2009 order directing it to address, among others, various market monitoring and mitigation issues. On July 8, 2009, various parties submitted comments on and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific aspects of the MISO’s and Independent Market Monitor’s proposals for market monitoring and mitigation and other issues that it believes the FERC should address and clarify. On October 23, 2009, FERC issued an order approving a MISO compliance filing that revised its tariff to provide for netting of demand resources, but prohibiting the netting of behind-the-meter generation.

FES Sales to Affiliates

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

On May 13-14, 2009, the Ohio Companies held an auction to secure generation supply for their PLR obligation. The results of the auction were accepted by the PUCO on May 14, 2009. Twelve bidders qualified to participate in the auction with nine successful bidders each securing a portion of the Ohio Companies' total supply needs. FES was the successful bidder for 51 tranches, and subsequently purchased 21 additional tranches from other bidders. The auction resulted in an overall weighted average wholesale price of 6.15 cents per KWH for generation and transmission. The new prices for PLR service went into effect with usage beginning June 1, 2009, and continuing through May 31, 2011.

 
53

 


On November 3, 2009, FES, Met-Ed, Penelec and Waverly restated their partial requirements power purchase agreement for 2010. The Fourth Restated Partial Requirements Agreement continues to limit the amount of capacity resources required to be supplied by FES to 3544 MW, but requires FES to supply essentially all of Met-Ed, Penelec, and Waverly’s energy requirements in 2010. Under the new agreement, Met-Ed, Penelec, and Waverly (Buyers) assign 1300 MW of existing energy purchases to FES to assist it in supplying Buyers’ power supply requirements and managing congestion expenses. FES can either sell the assigned power from the third party into the market or use it to serve the Met-Ed/Penelec load. FES is responsible for obtaining additional power supplies in the event of failure of supply of the assigned energy purchase contracts. Prices for the power sold by FES were increased to $42.77 and $44.42, respectively for Met-Ed and Penelec. In addition, FES agreed to reimburse Met-Ed and Penelec, respectively, for congestion expenses and marginal losses in excess of $208 million and $79 million as billed by PJM in 2010, and associated with delivery of power by FES under the Fourth Restated Partial Requirements Agreement. The Fourth Restated Partial Requirements Agreement terminates at the end of 2010.

 11. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

In December 2008, the FASB issued a standard on an employer’s disclosures about assets of a defined benefit pension or other postretirement plan. Requirements include disclosures about investment policies and strategies, categories of plan assets, fair value measurements of plan assets, and significant categories of risk. This standard is effective for fiscal years ending after December 15, 2009. FirstEnergy will expand its disclosures related to postretirement benefit plan assets.

In June 2009, the FASB amended the derecognition guidance in the Transfers and Servicing Topic of the FASB Accounting Standards Codification and eliminated the concept of a QSPE. The amended guidance requires an evaluation of all existing QSPEs to determine whether they must be consolidated. This standard is effective for financial asset transfers that occur in fiscal years beginning after November 15, 2009. FirstEnergy does not expect this standard to have a material effect upon its financial statements.

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

In August 2009, the FASB updated the Fair Value Measurement and Disclosures Topic, which provides guidance in determining fair value when a quoted price in an active market for an identical liability is not available. In such instances, an entity should measure fair value using one of the following approaches; (i) the quoted price of an identical liability when traded as an asset; (ii) the quoted price of a similar liability or a similar liability traded as an asset; (iii) a technique based on the amount an entity would pay to transfer the identical liability; or (iv) a technique based on the amount an entity would receive to enter into an identical liability. This standard is effective for the first reporting period, including interim periods, beginning after issuance, or October 1, 2009, for FirstEnergy. FirstEnergy does not expect this standard to have a material effect upon its financial statements.

12.  SEGMENT INFORMATION

FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio transitional generation services. The assets and revenues for all other business operations are below the quantifiable threshold for operating segments for separate disclosure as "reportable operating segments." FES and the Utilities do not have separate reportable operating segments.

The energy delivery services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems and is responsible for the regulated generation commodity operations of FirstEnergy's Pennsylvania and New Jersey electric utility subsidiaries. Its revenues are primarily derived from the delivery of electricity, cost recovery of regulatory assets, and default service electric generation sales to non-shopping customers in its Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES under Met-Ed's and Penelec's partial requirements purchased power agreements and from non-affiliated power suppliers as well as the net PJM transmission expenses related to the delivery of that generation load.

 
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The competitive energy services segment supplies electric power to its electric utility affiliates, provides competitive electricity sales primarily in Ohio, Pennsylvania, Maryland, Michigan and Illinois, owns or leases and operates FirstEnergy's generating facilities and purchases electricity to meet its sales obligations. The segment's net income is primarily derived from affiliated and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO to deliver electricity to the segment's customers. The segment's internal revenues represent sales to its affiliates in Ohio and Pennsylvania.

The Ohio transitional generation services segment represents the generation commodity operations of FirstEnergy's Ohio electric utility subsidiaries. Its revenues are primarily derived from electric generation sales to non-shopping customers under the PLR obligations of the Ohio Companies. Its results reflect the purchase of electricity from third parties and the competitive energy services segment through a CBP, the deferral and amortization of certain fuel costs authorized for recovery by the energy delivery services segment and the net MISO transmission revenues and expenses related to the delivery of generation load. This segment's total assets consist primarily of accounts receivable for generation revenues from retail customers.

 
55

 


Segment Financial Information
                               
               
Ohio
                   
   
Energy
   
Competitive
   
Transitional
                   
   
Delivery
   
Energy
   
Generation
         
Reconciling
       
Three Months Ended
 
Services
   
Services
   
Services
   
Other
   
Adjustments
   
Consolidated
 
   
(In millions)
 
September 30, 2009
                                   
External revenues
  $ 2,203     $ 490     $ 739     $ 6     $ (30 )   $ 3,408  
Internal revenues
    -       617       -       -       (617 )     -  
Total revenues
    2,203       1,107       739       6       (647 )     3,408  
Depreciation and amortization
    356       69       17       3       4       449  
Investment income
    46       159       -       -       (14 )     191  
Net interest charges
    117       28       -       2       173       320  
Income taxes
    93       121       6       (19 )     (73 )     128  
Net income (loss)
    139       183       9       17       (118 )     230  
Total assets
    22,753       10,691       270       674       286       34,674  
Total goodwill
    5,551       24       -       -       -       5,575  
Property additions
    182       224       -       14       12       432  
                                                 
September 30, 2008
                                               
External revenues
  $ 2,657     $ 460     $ 813     $ 5     $ (31 )   $ 3,904  
Internal revenues
    -       786       -       -       (786 )     -  
Total revenues
    2,657       1,246       813       5       (817 )     3,904  
Depreciation and amortization
    286       67       46       1       1       401  
Investment income
    48       13       1       -       (22 )     40  
Net interest charges
    101       31       1       -       44       177  
Income taxes
    188       109       14       (46 )     (27 )     238  
Net income
    283       164       19       48       (43 )     471  
Total assets
    23,088       9,360       270       457       387       33,562  
Total goodwill
    5,559       24       -       -       -       5,583  
Property additions
    170       285       -       85       20       560  
                                                 
Nine Months Ended
                                               
                                                 
September 30, 2009
                                               
External revenues
  $ 6,236     $ 1,329     $ 2,519     $ 18     $ (89 )   $ 10,013  
Internal revenues
    -       2,349       -       -       (2,349 )     -  
Total revenues
    6,236       3,678       2,519       18       (2,438 )     10,013  
Depreciation and amortization
    1,122       201       (24 )     7       11       1,317  
Investment income
    110       136       1       -       (40 )     207  
Net interest charges
    340       64       -       5       250       659  
Income taxes
    154       409       36       (56 )     (113 )     430  
Net income (loss)
    230       614       55       52       (197 )     754  
Total assets
    22,753       10,691       270       674       286       34,674  
Total goodwill
    5,551       24       -       -       -       5,575  
Property additions
    524       893       -       133       25       1,575  
                                                 
September 30, 2008
                                               
External revenues
  $ 7,051     $ 1,164     $ 2,203     $ 65     $ (57 )   $ 10,426  
Internal revenues
    -       2,266       -       -       (2,266 )     -  
Total revenues
    7,051       3,430       2,203       65       (2,323 )     10,426  
Depreciation and amortization
    782       179       61       2       10       1,034  
Investment income
    133       (1 )     1       6       (66 )     73  
Net interest charges
    303       86       1       -       133       523  
Income taxes
    436       212       42       (33 )     (72 )     585  
Net income
    655       317       62       96       (119 )     1,011  
Total assets
    23,088       9,360       270       457       387       33,562  
Total goodwill
    5,559       24       -       -       -       5,583  
Property additions
    621       1,430       -       106       20       2,177  
 
 
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.

 
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  13. SUPPLEMENTAL GUARANTOR INFORMATION

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has fully, unconditionally and irrevocably guaranteed all of FGCO's obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust's undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES' lease guaranty. This transaction is classified as an operating lease under GAAP for FES and FirstEnergy and as a financing for FGCO.

The condensed consolidating statements of income for the three-month and nine-month periods ended September 30, 2009 and 2008, consolidating balance sheets as of September 30, 2009 and December 31, 2008 and consolidating statements of cash flows for the nine months ended September 30, 2009 and 2008 for FES (parent and guarantor), FGCO and NGC (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FGCO and NGC are, therefore, reflected in FES' investment accounts and earnings as if operating lease treatment was achieved. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and the entries required to reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.



 
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FIRSTENERGY SOLUTIONS CORP.
 
                               
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
 
(Unaudited)
 
                               
For the Three Months Ended September 30, 2009
 
FES
   
FGCO
   
NGC
   
Eliminations
   
Consolidated
 
   
(In thousands)
 
                               
REVENUES
  $ 1,087,991     $ 477,679     $ 170,129     $ (631,227 )   $ 1,104,572  
                                         
EXPENSES:
                                       
Fuel
    9,278       241,953       43,462       -       294,693  
Purchased power from non-affiliates
    205,200       -       -       -       205,200  
Purchased power from affiliates
    621,996       9,233       35,290       (631,229 )     35,290  
Other operating expenses
    70,246       109,828       113,669       12,192       305,935  
Provision for depreciation
    1,051       30,469       35,832       (1,311 )     66,041  
General taxes
    4,351       11,331       6,018       -       21,700  
Total expenses
    912,122       402,814       234,271       (620,348 )     928,859  
                                         
OPERATING INCOME
    175,869       74,865       (64,142 )     (10,879 )     175,713  
                                         
OTHER INCOME (EXPENSE):
                                       
Investment income
    35       319       158,503       -       158,857  
Miscellaneous income, including net income
                                 
from equity investees
    100,668       744       1       (98,609 )     2,804  
Interest expense - affiliates
    (35 )     (1,267 )     (907 )     -       (2,209 )
Interest expense - other
    (15,358 )     (26,737 )     (16,205 )     16,113       (42,187 )
Capitalized interest
    49       15,381       2,439       -       17,869  
Total other income (expense)
    85,359       (11,560 )     143,831       (82,496 )     135,134  
                                         
INCOME BEFORE INCOME TAXES
    261,228       63,305       79,689       (93,375 )     310,847  
                                         
INCOME TAXES
    61,545       19,646       27,801       2,172       111,164  
                                         
NET INCOME
  $ 199,683     $ 43,659     $ 51,888     $ (95,547 )   $ 199,683  

 
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FIRSTENERGY SOLUTIONS CORP.
 
                               
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
 
(Unaudited)
 
                               
For the Three Months Ended September 30, 2008
 
FES
   
FGCO
   
NGC
   
Eliminations
   
Consolidated
 
   
(In thousands)
 
                               
REVENUES
  $ 1,222,783     $ 574,394     $ 267,017     $ (822,590 )   $ 1,241,604  
                                         
EXPENSES:
                                       
Fuel
    8,177       307,646       34,123       -       349,946  
Purchased power from non-affiliates
    221,493       -       -       -       221,493  
Purchased power from affiliates
    815,243       7,347       15,821       (822,590 )     15,821  
Other operating expenses
    35,596       110,701       120,697       12,190       279,184  
Provision for depreciation
    1,978       33,432       30,559       (1,336 )     64,633  
General taxes
    4,829       10,768       6,139       -       21,736  
Total expenses
    1,087,316       469,894       207,339       (811,736 )     952,813  
                                         
OPERATING INCOME
    135,467       104,500       59,678       (10,854 )     288,791  
                                         
OTHER INCOME (EXPENSE):
                                       
Investment income (loss)
    (122 )     (1,204 )     13,287       -       11,961  
Miscellaneous income, including net income
                                 
from equity investees
    102,899       689       -       (97,122 )     6,466  
Interest expense - affiliates
    (120 )     (4,963 )     (2,932 )     -       (8,015 )
Interest expense - other
    (8,464 )     (23,447 )     (17,183 )     16,325       (32,769 )
Capitalized interest
    41       11,376       978       -       12,395  
Total other income (expense)
    94,234       (17,549 )     (5,850 )     (80,797 )     (9,962 )
                                         
INCOME BEFORE INCOME TAXES
    229,701       86,951       53,828       (91,651 )     278,829  
                                         
INCOME TAXES
    44,046       31,863       14,995       2,270       93,174  
                                         
NET INCOME
  $ 185,655     $ 55,088     $ 38,833     $ (93,921 )   $ 185,655  

 
59

 


FIRSTENERGY SOLUTIONS CORP.
 
                               
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
 
(Unaudited)
 
                               
For the Nine Months Ended September 30, 2009
 
FES
   
FGCO
   
NGC
   
Eliminations
   
Consolidated
 
   
(In thousands)
 
                               
REVENUES
  $ 3,357,873     $ 1,726,715     $ 955,452     $ (2,368,210 )   $ 3,671,830  
                                         
EXPENSES:
                                       
Fuel
    16,400       755,632       99,128       -       871,160  
Purchased power from non-affiliates
    551,155       -       -       -       551,155  
Purchased power from affiliates
    2,351,879       16,333       149,746       (2,368,212 )     149,746  
Other operating expenses
    144,284       313,416       397,284       36,571       891,555  
Provision for depreciation
    3,087       90,680       103,135       (3,940 )     192,962  
General taxes
    12,826       35,289       18,246       -       66,361  
Total expenses
    3,079,631       1,211,350       767,539       (2,335,581 )     2,722,939  
                                         
OPERATING INCOME
    278,242       515,365       187,913       (32,629 )     948,891  
                                         
OTHER INCOME (EXPENSE):
                                       
Investment income
    83       758       134,882       -       135,723  
Miscellaneous income, including net income
                                       
from equity investees
    509,927       1,209       15       (498,311 )     12,840  
Interest expense - affiliates
    (103 )     (4,648 )     (3,752 )     -       (8,503 )
Interest expense - other
    (20,778 )     (72,762 )     (46,050 )     48,605       (90,985 )
Capitalized interest
    146       34,257       7,572       -       41,975  
Total other income (expense)
    489,275       (41,186 )     92,667       (449,706 )     91,050  
                                         
INCOME BEFORE INCOME TAXES
    767,517       474,179       280,580       (482,335 )     1,039,941  
                                         
INCOME TAXES
    99,751       166,902       98,893       6,629       372,175  
                                         
NET INCOME
  $ 667,766     $ 307,277     $ 181,687     $ (488,964 )   $ 667,766  

 
60

 


FIRSTENERGY SOLUTIONS CORP.
 
                               
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
 
(Unaudited)
 
                               
For the Nine Months Ended September 30, 2008
 
FES
   
FGCO
   
NGC
   
Eliminations
   
Consolidated
 
   
(In thousands)
 
                               
REVENUES
  $ 3,387,258     $ 1,707,320     $ 879,729     $ (2,562,309 )   $ 3,411,998  
                                         
EXPENSES:
                                       
Fuel
    13,920       876,077       92,188       -       982,185  
Purchased power from non-affiliates
    648,556       -       -       -       648,556  
Purchased power from affiliates
    2,549,892       12,417       75,834       (2,562,309 )     75,834  
Other operating expenses
    103,034       342,041       381,826       36,567       863,468  
Provision for depreciation
    3,885       90,058       80,646       (4,054 )     170,535  
General taxes
    14,971       33,842       15,915       -       64,728  
Total expenses
    3,334,258       1,354,435       646,409       (2,529,796 )     2,805,306  
                                         
OPERATING INCOME
    53,000       352,885       233,320       (32,513 )     606,692  
                                         
OTHER INCOME (EXPENSE):
                                       
Investment loss
    (333 )     (3,300 )     (2,699 )     -       (6,332 )
Miscellaneous income, including net income
                                       
from equity investees
    323,425       2,066       -       (305,710 )     19,781  
Interest expense - affiliates
    (252 )     (18,172 )     (7,529 )     -       (25,953 )
Interest expense - other
    (19,105 )     (73,112 )     (38,833 )     49,241       (81,809 )
Capitalized interest
    90       27,460       2,049       -       29,599  
Total other income (expense)
    303,825       (65,058 )     (47,012 )     (256,469 )     (64,714 )
                                         
INCOME BEFORE INCOME TAXES
    356,825       287,827       186,308       (288,982 )     541,978  
                                         
INCOME TAXES
    13,092       109,615       68,597       6,941       198,245  
                                         
NET INCOME
  $ 343,733     $ 178,212     $ 117,711     $ (295,923 )   $ 343,733  

 
61

 

FIRSTENERGY SOLUTIONS CORP.
 
                               
CONDENSED CONSOLIDATING BALANCE SHEETS
 
(Unaudited)
 
                               
As of September 30, 2009
 
FES
   
FGCO
   
NGC
   
Eliminations
   
Consolidated
 
   
(In thousands)
 
ASSETS
                             
CURRENT ASSETS:
                             
Cash and cash equivalents
  $ 266,859     $ 99     $ -     $ -     $ 266,958  
Receivables-
                                       
Customers
    155,489       -       -       -       155,489  
Associated companies
    278,670       186,263       106,551       (227,097 )     344,387  
Other
    15,310       12,858       19,411       -       47,579  
Notes receivable from associated companies
    134,283       200,692       93,041       -       428,016  
Materials and supplies, at average cost
    9,925       304,358       213,995       -       528,278  
Prepayments and other
    90,377       19,064       10,921       -       120,362  
      950,913       723,334       443,919       (227,097 )     1,891,069  
                                         
PROPERTY, PLANT AND EQUIPMENT:
                                       
In service
    90,179       5,508,790       5,041,783       (386,054 )     10,254,698  
Less - Accumulated provision for depreciation
    12,590       2,785,417       1,860,060       (170,235 )     4,487,832  
      77,589       2,723,373       3,181,723       (215,819 )     5,766,866  
Construction work in progress
    4,179       1,830,141       361,679       -       2,195,999  
      81,768       4,553,514       3,543,402       (215,819 )     7,962,865  
                                         
INVESTMENTS:
                                       
Nuclear plant decommissioning trusts
    -       -       1,101,884       -       1,101,884  
Investment in associated companies
    4,327,059       -       -       (4,327,059 )     -  
Long-term notes receivable from associated companies
    -       -       8,817       -       8,817  
Other
    1,320       25,121       201       -       26,642  
      4,328,379       25,121       1,110,902       (4,327,059 )     1,137,343  
DEFERRED CHARGES AND OTHER ASSETS:
                                       
Accumulated deferred income taxes
    12,331       391,899       -       (366,131 )     38,099  
Lease assignment receivable from associated companies
    -       71,356       -       -       71,356  
Goodwill
    24,248       -       -       -       24,248  
Property taxes
    -       27,494       22,610       -       50,104  
Unamortized sale and leaseback costs
    -       2,938       -       55,412       58,350  
Other
    194,916       68,278       16,619       (53,679 )     226,134  
      231,495       561,965       39,229       (364,398 )     468,291  
    $ 5,592,555     $ 5,863,934     $ 5,137,452     $ (5,134,373 )   $ 11,459,568  
                                         
LIABILITIES AND CAPITALIZATION
                                       
CURRENT LIABILITIES:
                                       
Currently payable long-term debt
  $ 726     $ 697,986     $ 951,240     $ (18,186 )   $ 1,631,766  
Short-term borrowings-
                                       
Associated companies
    -       -       -       -       -  
Other
    100,000       -       -       -       100,000  
Accounts payable-
                                       
Associated companies
    130,669       212,778       234,626       (190,891 )     387,182  
Other
    30,890       125,163       -       -       156,053  
Accrued taxes
    114,043       29,489       16,791       (54,749 )     105,574  
Other
    41,828       120,107       27,772       38,081       227,788  
      418,156       1,185,523       1,230,429       (225,745 )     2,608,363  
                                         
CAPITALIZATION:
                                       
Common stockholder's equity
    3,607,283       2,252,002       2,054,817       (4,306,819 )     3,607,283  
Long-term debt and other long-term obligations
    1,519,585       1,865,313       533,990       (1,278,796 )     2,640,092  
      5,126,868       4,117,315       2,588,807       (5,585,615 )     6,247,375  
                                         
NONCURRENT LIABILITIES:
                                       
Deferred gain on sale and leaseback transaction
    -       -       -       1,001,298       1,001,298  
Accumulated deferred income taxes
    -       -       324,311       (324,311 )     -  
Accumulated deferred investment tax credits
    -       37,129       22,350       -       59,479  
Asset retirement obligations
    -       25,011       881,188       -       906,199  
Retirement benefits
    32,043       168,054       -       -       200,097  
Property taxes
    -       27,494       22,610       -       50,104  
Lease market valuation liability
    -       273,624       -       -       273,624  
Other
    15,488       29,784       67,757       -       113,029  
      47,531       561,096       1,318,216       676,987       2,603,830  
    $ 5,592,555     $ 5,863,934     $ 5,137,452     $ (5,134,373 )   $ 11,459,568  

 
62

 


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

 
63

 


FIRSTENERGY SOLUTIONS CORP.
 
                               
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
                               
For the Nine Months Ended September 30, 2009
 
FES
   
FGCO
   
NGC
   
Eliminations
   
Consolidated
 
   
(In thousands)
 
                               
NET CASH PROVIDED FROM OPERATING ACTIVITIES
  $ (37,990 )   $ 520,169     $ 408,364     $ (8,732 )   $ 881,811  
                                         
CASH FLOWS FROM FINANCING ACTIVITIES:
                                       
New Financing-
                                       
Long-term debt
    1,498,087       524,710       333,965       -       2,356,762  
Equity contributions from parent
    -       100,000       150,000       (250,000 )     -  
Redemptions and Repayments-
                                       
Long-term debt
    (1,507 )     (258,583 )     (366,857 )     8,734       (618,213 )
Short-term borrowings, net
    (901,119 )     (257,357 )     (6,347 )     -       (1,164,823 )
Other
    (11,583 )     (5,261 )     (3,160 )     (2 )     (20,006 )
Net cash provided from financing activities
    583,878       103,509       107,601       (241,268 )     553,720  
                                         
CASH FLOWS FROM INVESTING ACTIVITIES:
                                       
Property additions
    (2,224 )     (439,531 )     (400,845 )     -       (842,600 )
Proceeds from asset sales
    -       16,129       -       -       16,129  
Sales of investment securities held in trusts
    -       -       2,152,717       -       2,152,717  
Purchases of investment securities held in trusts
    -       -       (2,175,135 )     -       (2,175,135 )
Loan to associated companies, net
    (27,054 )     (178,746 )     (93,041 )     -       (298,841 )
Investment in subsidiary
    (250,000 )     -       -       250,000       -  
Other
    249       (21,470 )     339       -       (20,882 )
Net cash used for investing activities
    (279,029 )     (623,618 )     (515,965 )     250,000       (1,168,612 )
                                         
Net change in cash and cash equivalents
    266,859       60       -       -       266,919  
Cash and cash equivalents at beginning of period
    -       39       -       -       39  
Cash and cash equivalents at end of period
  $ 266,859     $ 99     $ -     $ -     $ 266,958  
 

 
64

 
 

FIRSTENERGY SOLUTIONS CORP.
 
                               
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
 
(Unaudited)
 
                               
For the Nine Months Ended September 30, 2008
 
FES
   
FGCO
   
NGC
   
Eliminations
   
Consolidated
 
   
(In thousands)
 
                               
NET CASH PROVIDED FROM OPERATING ACTIVITIES:
  $ 47,463     $ 267,933     $ 247,054     $ (8,317 )   $ 554,133  
                                         
CASH FLOWS FROM FINANCING ACTIVITIES:
                                       
New Financing-
                                       
Long-term debt
    -       328,325       209,050       -       537,375  
Equity contribution from parent
    280,000       675,000       175,000       (850,000 )     280,000  
Short-term borrowings, net
    700,000       -       139,363       (91,677 )     747,686  
Redemptions and Repayments-
                                       
Long-term debt
    (1,777 )     (286,776 )     (180,666 )     8,317       (460,902 )
Short-term borrowings, net
    -       (91,677 )     -       91,677       -  
Common stock dividend payment
    (43,000 )     -       -       -       (43,000 )
Net cash provided from financing activities
    935,223       624,872       342,747       (841,683 )     1,061,159  
                                         
CASH FLOWS FROM INVESTING ACTIVITIES:
                                       
Property additions
    (38,481 )     (778,329 )     (600,395 )     -       (1,417,205 )
Proceeds from asset sales
    -       15,218       -       -       15,218  
Sales of investment securities held in trusts
    -       -       596,291       -       596,291  
Purchases of investment securities held in trusts
    -       -       (624,899 )     -       (624,899 )
Loan repayments from (loans to) associated companies, net
    (94,755 )     (38,399 )     69,012       -       (64,142 )
Investment in subsidiary
    (850,000 )     -       -       850,000       -  
Restricted funds for debt redemption
    -       (52,090 )     (29,550 )     -       (81,640 )
Other
    550       (39,205 )     (260 )     -       (38,915 )
Net cash used for investing activities
    (982,686 )     (892,805 )     (589,801 )     850,000       (1,615,292 )
                                         
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  

 


 
65

 



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 September 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. As discussed in Note 7 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, 2008 consolidated balance sheet reflects this change.
 
 
 
 
PricewaterhouseCoopers LLP
Cleveland, Ohio
November 6, 2009


 
66

 



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 September 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2008, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
 
 
 
 
PricewaterhouseCoopers LLP
Cleveland, Ohio
November 6, 2009




 
67

 



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 September 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. As discussed in Note 7 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, 2008 consolidated balance sheet reflects this change.
 
 
 
 
PricewaterhouseCoopers LLP
Cleveland, Ohio
November 6, 2009



 
68

 



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 September 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. As discussed in Note 7 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, 2008 consolidated balance sheet reflects this change.
 
 
 
 
PricewaterhouseCoopers LLP
Cleveland, Ohio
November 6, 2009



 
69

 



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 September 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. As discussed in Note 7 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, 2008 consolidated balance sheet reflects this change.
 
 
 
 
PricewaterhouseCoopers LLP
Cleveland, Ohio
November 6, 2009




 
70

 



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 September 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2008, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
 
 
 
 
PricewaterhouseCoopers LLP
Cleveland, Ohio
November 6, 2009




 
71

 



Report of Independent Registered Public Accounting Firm








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

We have reviewed the accompanying consolidated balance sheet of Metropolitan Edison Company and its subsidiary as of September 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2008, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
 
 
 
 
PricewaterhouseCoopers LLP
Cleveland, Ohio
November 6, 2009




 
72

 



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 September 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2008, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
 
 
 
 
PricewaterhouseCoopers LLP
Cleveland, Ohio
November 6, 2009





 
73

 

Item 2.    Management's Discussion and Analysis of Registrant and Subsidiaries


FIRSTENERGY CORP.

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


EXECUTIVE SUMMARY

Net income in the third quarter of 2009 was $234 million, or basic and diluted earnings of $0.77 per share of common stock, compared with net income of $471 million, or basic earnings of $1.55 per share of common stock ($1.54 diluted) in the third quarter of 2008. Results in the third quarter of 2009 include a loss of $0.30 per share resulting from the redemption of $1.2 billion of our 6.45% notes, partially offset by $0.25 per share of investment income resulting primarily from the sale of securities held in our nuclear decommissioning trust. Net income in the first nine months of 2009 was $768 million or basic earnings of $2.52 per share of common stock ($2.51 diluted), compared with net income of $1.01 billion, or basic earnings of $3.32 per share of common stock ($3.29 diluted) in the first nine months of 2008.

Change in Basic Earnings Per Share
From Prior Year Periods
 
  Three Months
Ended
September 30
 
  Nine Months
Ended
September 30
 
               
Basic Earnings Per Share – 2008
   
$
1.55
   
$
3.32
 
Gain on non-core asset sales
   
-
   
0.46
 
Litigation settlement – 2008
   
-
   
(0.03
)
Debt redemption premium - 2009
   
(0.30
)
 
(0.30
)
Organizational restructuring costs – 2009
   
(0.07
)
 
(0.14
)
Regulatory charges – 2009
   
-
   
(0.55
)
Investment Income
   
0.17
   
0.12
 
Trust securities impairments
   
0.08
   
0.08
 
Income tax adjustments
   
(0.12
)
 
(0.09
)
Revenues (excluding asset sales)
   
(1.04
)
 
(1.29
)
Fuel and purchased power
   
0.10
   
0.03
 
Transmission costs
   
0.30
   
0.56
 
Amortization of regulatory assets, net
   
(0.06
)
 
(0.03
)
Other expenses
   
0.16
   
0.38
 
Basic Earnings Per Share – 2009
   
$
0.77
   
$
2.52
 

 
Regulatory Matters 

Ohio Regulatory Update 

On August 6, 2009, the PUCO withdrew proposed rules it had forwarded to the Joint Committee on Agency Rules Review regarding implementation of the alternative energy portfolio standards created by SB221, incorporating energy efficiency requirements, long-term forecasting and planning for greenhouse gas reporting and carbon dioxide control. The rules remain under consideration. On October 15, 2009, the PUCO issued a second Entry on Rehearing, modifying certain of its previous rules. Modified rules previously withdrawn from JCARR were refiled with JCARR on October 16 and October 19, 2009. The rules set out the manner in which the electric utilities, including the Ohio companies, will be required to comply with benchmarks contained in SB 221 related to the employment of alternative energy resources, energy efficiency/peak demand reduction programs as well as greenhouse gas reporting requirements and changes to long term forecast reporting requirements. The rules severely restrict the types of renewable energy resources and energy efficiency and peak reduction programs that may be included toward meeting the statutory goals, which is expected to significantly increase the cost of compliance for the Ohio companies' customers. It is currently unclear what form the final rules may take or their potential impact on the Ohio Companies. On October 23, 2009, the rules were placed in a “to be re-filed” status by JCARR. It is currently unclear what form the final rules may take or their potential impact on the Ohio Companies. As a result of this uncertainty surrounding the rules, as well as the Commission’s failure to address certain energy efficiency application submitted by the Ohio Companies throughout the year and the Commission’s recent directive to postpone the launch of a Commission-approved energy efficiency program, the Ohio Companies, on October 27, 2009, submitted an application to amend their 2009 statutory energy efficiency benchmarks to zero. Absent this regulatory relief the Ohio Companies may not be able to meet their 2009 statutory energy efficiency benchmarks, which may result in the assessment of a forfeiture by the PUCO. The Ohio Companies asked the Commission to issue a ruling on or before December 2, 2009.

 
74

 


On August 19, 2009, the PUCO approved FirstEnergy’s proposal to accelerate the recovery of deferred costs. The principal amount plus carrying charges through August 31, 2009, for these deferrals was $305.1 million. Accelerated recovery began September 1, 2009, and will be collected in the 18 non-summer months through May 31, 2011.

On October 20, 2009, the Ohio Companies filed an MRO to procure electric generation service for the period beginning June 1, 2011. The proposed MRO would establish a CBP to secure generation supply for customers who do not shop with an alternative supplier and would be similar, in all material respects, to the CBP conducted in May 2009 in that it would procure energy, capacity and certain transmission services on a slice of system basis. However, unlike the May 2009 CBP, the MRO would include multiple bidding sessions and multiple products with different delivery periods for generation supply designed to reduce potential volatility, reduce supplier risk and encourage bidder participation. A technical conference was held on October 29, 2009, at the PUCO. Pursuant to SB221, the PUCO has 90 days to determine whether the MRO meets certain statutory requirements, therefore, the Ohio Companies have requested a PUCO determination by January 18, 2010. Under a determination that such statutory requirements were met, the Ohio Companies would be able to implement the MRO and conduct the CBP

In August and October 2009, the Ohio Companies conducted RFPs to Secure Renewable Energy Credits (RECs). The RFPs include solar and other renewable energy RECs, including those generated in Ohio. The RFCs from these two RFPs will be used to help meet the renewable energy requirements established under Senate Bill 221 for 2009, 2010 and 2011.

Pennsylvania Regulatory Update 

Met-Ed and Penelec Default Service Plan Settlements

On August 12, 2009, Met-Ed and Penelec filed a settlement agreement with the PPUC for the generation procurement plan covering the period January 1, 2011, through May 31, 2013, reflecting the settlement on all but two issues. The settlement plan is designed to provide adequate and reliable service as required by Pennsylvania law through a prudent mix of long-term, short-term and spot-market generation supply as required by Act 129. The settlement plan proposes a staggered procurement schedule, which varies by customer class. If approved, generation procurement would begin in January 2010.

On September 2, 2009, the ALJ issued a Recommended Decision (RD) and adopted the Companies’ positions on two reserved issues. Exceptions to the ALJ RD were filed on September 22, 2009, with reply exceptions being filed on October 2, 2009. The PPUC's final decision is expected in November 2009.

By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30 day comment period on whether “the Restructuring Settlement allows NUG over collection for select and isolated months to be used to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists.”   In response to the Tentative Order comments were filed by the Office of Small Business Advocate, Office of Consumer Advocate, York County Solid Waste and Refuse Authority, ARIPPA, the Met-Ed Industrial Users Group and Penelec Industrial Customer Alliance objecting to the above accounting method utilized by Met-Ed and Penelec. The Companies will file reply comments on October 26, 2009.

Pennsylvania Smart Meter Plan

On August 14, 2009, Penn, Met-Ed and Penelec (the Companies) filed a Smart Meter Technology Procurement and Installation Plan with the PPUC as required by Act 129. The plan includes proposed tariff riders to recover the costs of implementation of the plan and an assessment period of twenty-four months to evaluate needs, select technology, secure vendors, train personnel, install and support test equipment and establish a detailed meter deployment schedule consistent with the requirements of Act 129. At the end of the assessment period, the Companies will submit to the PPUC a supplement to the plan to set forth in detail the Companies’ proposal for the full scale deployment of smart meters. The Companies are asking the PPUC to approve, as part the plan, both the proposed recovery mechanism and the recovery of costs of the assessment period, currently estimated at $29.5 million, through such mechanism.

New Jersey Solar Renewable Energy Certificates

JCP&L, in collaboration with another New Jersey electric utility, Atlantic City Electric Company (ACE), announced a RFP to secure Solar Renewable Energy Certificates (SREC) as part of the NJBPU's effort to support new solar energy projects. The RFP process was established to help create long-term agreements to purchase and sell SRECs to provide a stable basis for financing new solar generation projects in the companies' service areas. A total of 61 MW of solar generating capacity - 19 for ACE and 42 for JCP&L - will be solicited to help meet New Jersey Renewable Portfolio Standards. The first solicitation was conducted in August; subsequent solicitations will occur over the next three years. The costs of this program are expected to be fully recoverable through a per KWH rate approved by the NJBPU and applied to all customers.

 
75

 


Operational Matters

Fremont Energy Center

On September 22, 2009, FirstEnergy announced it expects to complete construction of the Fremont Energy Center by the end of 2010. Originally acquired by FGCO in January 2008, the Fremont Energy Center includes two natural gas combined-cycle combustion turbines and a steam turbine capable of producing 544 MW of load-following capacity and 163 MW of peaking capacity. With the accelerated construction schedule, FES estimates the remaining cost to complete the project to be $180 million.

Nuclear Outage

On October 12, 2009, NGC's Beaver Valley Nuclear Power Station Unit 2, located in Shippingport, Pennsylvania began a scheduled refueling and maintenance outage. During the outage, 60 of the 157 fuel assemblies will be exchanged and safety inspections conducted. In addition, numerous improvement projects will be completed to ensure continued safe and reliable operations.

PJM Regional Transmission Organization (RTO) Integration

As described in the “FERC Matters” section of this document, on August 17, 2009, FirstEnergy filed an application with the FERC to consolidate its transmission assets and operations into PJM. Currently FirstEnergy's transmission assets and operations are divided between PJM and MISO. The consolidation would move the transmission assets that are part of FirstEnergy's ATSI subsidiary and are located within the footprint of FirstEnergy's Ohio utilities and Pennsylvania Power - into PJM. If approved, the consolidation would provide customers with the benefits of a more fully developed retail choice market, and FirstEnergy and its Utilities with the operating efficiencies of a single RTO - with one set of rules, procedures and protocols. To ensure a definitive ruling at the same time FERC rules on its request to integrate ATSI into PJM, on October 19, 2009, FirstEnergy filed a related complaint with FERC on the issue of allocating transmission costs to the ATSI footprint for high voltage transmission projects approved prior to FirstEnergy’s integration into PJM.

FirstEnergy has requested that FERC rule on its application by December 17, 2009, to provide time to permit management to make a decision on whether to integrate ATSI into PJM prior to the 2010 Base Residual Auction for capacity. Subject to a satisfactory FERC ruling, the integration is expected to be complete on June 1, 2011, to coincide with delivery of power under the next competitive generation procurement process for FirstEnergy's Ohio companies.

On September 4, 2009, the PUCO opened a case to take comments from Ohio stakeholders regarding the RTO consolidation. FirstEnergy filed extensive comments in the PUCO case on September 25, 2009, and reply comments on October 13, 2009, and attended a public hearing on September 15, 2009, to respond to questions regarding the RTO consolidation.

Several parties have intervened in the regulatory dockets at the FERC and the PUCO. Certain interveners have commented and protested particular elements of the proposed RTO consolidation, including an exit fee to MISO, integration costs to PJM, and cost-allocations of future transmission upgrades in PJM and MISO. The result of these comments and protests could delay or otherwise have a material financial effect on the proposed RTO consolidation.

Voluntary Enhanced  Retirement Option

FirstEnergy’s VERO enrollment period concluded September 16, 2009. The VERO was accepted by a total 397 non-represented employees and 318 union employees.

FirstEnergy Solutions Offers Economic Support Program

In September 2009, FES introduced Powering Our Communities, an innovative program that offers economic support to communities in the OE, CEI and TE service areas that purchase discounted electric generation supply from FES through government aggregation programs. The program will provide up-front grants to local Ohio communities and long-term electric generation price savings.

Smart Grid Proposal

On August 6, 2009, FirstEnergy filed an application for economic stimulus funding with the U.S. Department of Energy under the American Recovery and Reinvestment Act that proposed investing $114 million on smart grid technologies to improve the reliability and interactivity of its electric distribution infrastructure in its three-state service area. The application requested $57 million, which represents half of the funding needed for targeted projects in communities served by the Utilities. On October 27, 2009, FirstEnergy received notice from the Department of Energy that its application was selected for award negotiations. However, no assurance can be given that we will receive any such award.

 
76

 


Financial Matters

Rating Agency Update

On August 3, 2009, Moody's Investor Service upgraded the senior secured debt ratings of FirstEnergy’s seven regulated utilities as follows:  CEI and TE were each upgraded to Baa1 from Baa2, and JCP&L, Met-Ed, OE, Penelec and Penn were each upgraded to A3 from Baa1.

Financing Activities

On August 7, 2009, FES issued 5, 12 and 30-year unsecured senior notes totaling $1.5 billion. The notes bear interest at an annual rate of 4.80%, 6.05% and 6.80%, respectively. Proceeds received from the issuance of the notes were used to pay down borrowings under the $2.75 billion revolving credit facility that FES shares with FirstEnergy and certain other subsidiaries, which made borrowing capacity available to FirstEnergy under the facility to fund a cash tender offer for $1.2 billion of its 6.45% notes, Series B, due 2011. FirstEnergy announced the tender offer on August 4, 2009 and completed it on September 1, 2009. $250 million of the 2011 notes remain outstanding.

On August 14, 2009, $177 million of PCRBs were issued and sold on behalf of FGCO relating to air quality compliance expenditures at the Sammis Plant. The PCRBs bear interest at an annual rate of 5.7% and mature on August 1, 2020.

On August 18, 2009, CEI issued $300 million of FMB that bear interest at an annual rate of 5.5% and mature on August 15, 2024. A portion of the proceeds will  be used to replace $150 million of CEI’s 7.43% Series D Secured Notes that mature on November 1, 2009. The remaining proceeds were used to repay a portion of CEI’s short-term borrowings.

On September 2, 2009, the Utilities and ATSI voluntarily contributed $500 million to the pension plan. On September 30, 2009, Penelec issued $500 million of unsecured notes, of which $250 million mature in 2020 and $250 million mature in 2038. The 2020 notes and 2038 notes bear interest at an annual rate of 5.20% and 6.15%, respectively.

On October 1, 2009, FGCO and NGC purchased $52.1 million and $29.6 million of PCRBs subject to mandatory purchase. Subject to market conditions, FGCO and NGC plan to remarket the purchased PCRBs in the near future.

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. This business segment derives its revenues principally from the delivery of electricity within FirstEnergy's service areas and the sale of electric generation service to retail customers who have not selected an alternative supplier (default service).

·  
Competitive Energy Services supplies the electric power needs of end-use customers through retail and wholesale arrangements, including associated company power sales to meet a portion of the PLR and default service requirements of FirstEnergy's Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland, Michigan and Illinois. This business segment owns or leases and operates 19 generating facilities with a net demonstrated capacity of 13,710 MW and also purchases electricity to meet sales obligations. The segment's net income is derived primarily from affiliated company power sales and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission and ancillary costs charged by PJM and MISO to deliver energy to the segment's customers.

·  
Ohio Transitional Generation Services supplies the electric power needs of non-shopping customers under the default service requirements of FirstEnergy's Ohio Companies. The segment's net income is derived primarily from electric generation sales revenues (including transmission) less the cost of power purchased through the Ohio Companies' CBP and transmission and ancillary costs charged by MISO to deliver energy to retail customers.

RESULTS OF OPERATIONS

The financial results discussed below include revenues and expenses from transactions among FirstEnergy's business segments. A reconciliation of segment financial results is provided in Note 12 to the consolidated financial statements. Earnings by major business segment were as follows:

 
77

 



   
Three Months Ended September 30
 
Nine Months Ended September 30
 
       
Increase
     
Increase
 
   
2009
 
2008
 
(Decrease)
 
2009
 
2008
 
(Decrease)
 
   
(In millions, except per share data)
 
Earnings By Business Segment:
                         
Energy delivery services
 
$
139
 
$
283
 
$
(144
)
$
230
 
$
655
 
$
(425
)
Competitive energy services
   
183
   
164
   
19
   
614
   
317
   
297
 
Ohio transitional generation services
   
9
   
19
   
(10
)
 
55
   
62
   
(7
)
Other and reconciling adjustments*
   
(101
)
 
5
   
(106
)
 
(145
)
 
(24
)
 
(121
)
Total
 
$
230
 
$
471
 
$
(241
)
$
754
 
$
1,010
 
$
(256
)
                                       
Basic Earnings Per Share
 
$
.77
 
$
1.55
 
$
(.78
)
$
2.52
 
$
3.32
 
$
(.80
)
Diluted Earnings Per Share
 
$
.77
 
$
1.54
 
$
(.77
)
$
2.51
 
$
3.29
 
$
(.78
)
                                       
* Consists primarily of interest expense related to holding company debt, corporate support services revenues and expenses, noncontrolling interests and the elimination of intersegment transactions.
 
 
 
Summary of Results of Operations – Third Quarter 2009 Compared with Third Quarter 2008

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

               
Ohio
             
   
Energy
   
Competitive
   
Transitional
   
Other and
       
   
Delivery
   
Energy
   
Generation
   
Reconciling
   
FirstEnergy
 
Third Quarter 2009 Financial Results
 
Services
   
Services
   
Services
   
Adjustments
   
Consolidated
 
   
(In millions)
 
Revenues:
                             
External
                             
Electric
  $ 2,067     $ 444     $ 737     $ -     $ 3,248  
Other
    136       46       2       (24 )     160  
Internal
    -       617       -       (617 )     -  
Total Revenues
    2,203       1,107       739       (641 )     3,408  
                                         
Expenses:
                                       
Fuel
    -       302       -       -       302  
Purchased power
    1,011       205       714       (617 )     1,313  
Other operating expenses
    373       331       (9 )     (30 )     665  
Provision for depreciation
    112       69       -       7       188  
Amortization of regulatory assets
    244       -       17       -       261  
Deferral of new regulatory assets
    -       -       -       -       -  
General taxes
    160       27       2       3       192  
Total Expenses
    1,900       934       724       (637 )     2,921  
                                         
Operating Income
    303       173       15       (4 )     487  
Other Income (Expense):
                                       
Investment income
    46       159       -       (14 )     191  
Interest expense
    (118 )     (46 )     -       (191 )     (355 )
Capitalized interest
    1       18       -       16       35  
Total Other Expense
    (71 )     131       -       (189 )     (129 )
                                         
Income Before Income Taxes
    232       304       15       (193 )     358  
Income taxes
    93       121       6       (92 )     128  
Net Income
    139       183       9       (101 )     230  
Less: Noncontrolling interest income (loss)
    -       -       -       (4 )     (4 )
Earnings available to FirstEnergy Corp.
  $ 139     $ 183     $ 9     $ (97 )   $ 234  
 

 
78

 

 
               
Ohio
             
   
Energy
   
Competitive
   
Transitional
   
Other and
       
   
Delivery
   
Energy
   
Generation
   
Reconciling
   
FirstEnergy
 
Third Quarter 2008 Financial Results
 
Services
   
Services
   
Services
   
Adjustments
   
Consolidated
 
   
(In millions)
 
Revenues:
                             
External
                             
Electric
  $ 2,487     $ 381     $ 781     $ -     $ 3,649  
Other
    170       79       32       (26 )     255  
Internal
    -       786       -       (786 )     -  
Total Revenues
    2,657       1,246       813       (812 )     3,904  
                                         
Expenses:
                                       
Fuel
    -       356       -       -       356  
Purchased power
    1,248       221       623       (786 )     1,306  
Other operating expenses
    430       285       110       (31 )     794  
Provision for depreciation
    99       67       -       2       168  
Amortization of regulatory assets, net
    263       -       28       -       291  
Deferral of new regulatory assets
    (76 )     -       18       -       (58 )
General taxes
    169       26       1       5       201  
Total Expenses
    2,133       955       780       (810 )     3,058  
                                         
Operating Income
    524       291       33       (2 )     846  
Other Income (Expense):
                                       
Investment income
    48       13       1       (22 )     40  
Interest expense
    (102 )     (44 )     (1 )     (45 )     (192 )
Capitalized interest
    1       13       -       1       15  
Total Other Expense
    (53 )     (18 )     -       (66 )     (137 )
                                         
Income Before Income Taxes
    471       273       33       (68 )     709  
Income taxes
    188       109       14       (73 )     238  
Net Income
    283       164       19       5       471  
Less: Noncontrolling interest income
    -       -       -       -       -  
Earnings available to FirstEnergy Corp.
  $ 283     $ 164     $ 19     $ 5     $ 471  
                                         
Changes Between Third Quarter 2009 and
                                       
Third Quarter 2008 Financial Results
                                       
Increase (Decrease)
                                       
                                         
Revenues:
                                       
External
                                       
Electric
  $ (420 )   $ 63     $ (44 )   $ -     $ (401 )
Other
    (34 )     (33 )     (30 )     2       (95 )
Internal
    -       (169 )     -       169       -  
Total Revenues
    (454 )     (139 )     (74 )     171       (496 )
                                         
Expenses:
                                       
Fuel
    -       (54 )     -       -       (54 )
Purchased power
    (237 )     (16 )     91       169       7  
Other operating expenses
    (57 )     46       (119 )     1       (129 )
Provision for depreciation
    13       2       -       5       20  
Amortization of regulatory assets
    (19 )     -       (11 )     -       (30 )
Deferral of new regulatory assets
    76       -       (18 )     -       58  
General taxes
    (9 )     1       1       (2 )     (9 )
Total Expenses
    (233 )     (21 )     (56 )     173       (137 )
                                         
Operating Income
    (221 )     (118 )     (18 )     (2 )     (359 )
Other Income (Expense):
                                       
Investment income
    (2 )     146       (1 )     8       151  
Interest expense
    (16 )     (2 )     1       (146 )     (163 )
Capitalized interest
    -       5       -       15       20  
Total Other Expense
    (18 )     149       -       (123 )     8  
                                         
Income Before Income Taxes
    (239 )     31       (18 )     (125 )     (351 )
Income taxes
    (95 )     12       (8 )     (19 )     (110 )
Net Income
    (144 )     19       (10 )     (106 )     (241 )
Less: Noncontrolling interest income
    -       -       -       (4 )     (4 )
Earnings available to FirstEnergy Corp.
  $ (144 )   $ 19     $ (10 )   $ (102 )   $ (237 )
 

 
79

 


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

Net income decreased $144 million to $139 million in the third quarter of 2009 compared to $283 million in the third quarter of 2008, primarily due to lower revenues and decreased deferrals of new regulatory assets, partially offset by lower purchased power and other operating expenses.

Revenues –

The decrease in total revenues resulted from the following sources:

   
Three Months
       
   
Ended September 30
 
Increase
 
Revenues by Type of Service
 
2009
 
2008
 
(Decrease)
 
   
(In millions)
 
Distribution services
 
$
915
 
$
1,100
 
$
(185
)
Generation sales:
                   
   Retail
   
825
   
986
   
(161
)
   Wholesale
   
195
   
286
   
(91
)
Total generation sales
   
1,020
   
1,272
   
(252
)
Transmission
   
221
   
241
   
(20
)
Other
   
47
   
44
   
3
 
Total Revenues
 
$
2,203
 
$
2,657
 
$
(454
)

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

Electric Distribution KWH Deliveries
     
Residential
   
(8.1)
%
Commercial
   
(6.2)
%
Industrial
   
(15.7)
%
Total Distribution KWH Deliveries
   
(9.8)
%

Lower deliveries to residential customers reflected decreased weather-related usage in the third quarter of 2009, as cooling degree days decreased by 14% from the same period in 2008. The decrease in distribution deliveries to commercial and industrial customers was primarily due to economic conditions in FirstEnergy's service territory. In the industrial sector, KWH deliveries declined due to major automotive customers (10.1%) and steel customers (42.3%). Transition charges for OE and TE that ceased effective January 1, 2009 with the full recovery of related costs, and the transition rate reduction for CEI effective June 1, 2009, were partially offset by PUCO-approved distribution rate increases (see Regulatory Matters – Ohio).

The following table summarizes the price and volume factors contributing to the $252 million decrease in generation revenues in the third quarter of 2009 compared to the third quarter of 2008:

Sources of Change in Generation Revenues
 
 
(Decrease)
 
   
(In millions)
 
Retail:
       
  Effect of 12% decrease in sales volumes
 
$
(113)
 
  Change in prices
   
(48)
 
     
(161)
 
Wholesale:
       
  Effect of 18% decrease in sales volumes
   
(51)
 
  Change in prices
   
(40)
 
     
(91)
 
Decrease in Generation Revenues
 
$
(252)
 

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

 
80

 


Transmission revenues decreased $20 million primarily due to lower PJM transmission revenues partially offset by higher transmission rates for Met-Ed resulting from the annual update to its TSC rider in June 2009. Met-Ed and Penelec defer the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings (see Regulatory Matters – Pennsylvania).

Expenses –

Total expenses decreased by $233 million due to the net impact of the following:

 
·
Purchased power costs were $237 million lower in the third quarter of 2009 due to lower volume requirements and an increase in the amount of NUG costs deferred. JCP&L, Met-Ed and Penelec are permitted to defer for future collection from customers the amounts by which costs incurred under NUG agreements exceed amounts collected through rates. 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
 
$
38
 
Change due to decreased volumes
   
(209
)
     
(171
)
Purchases from FES:
       
Change due to decreased unit costs
   
(7
)
Change due to increased volumes
   
19
 
     
12
 
         
Increase in NUG costs deferred
   
(78
)
Net Decrease in Purchased Power Costs
 
$
(237
)

·      PJM transmission expenses were lower by $83 million resulting from reduced volumes and congestion costs.

·      Contractor and material costs decreased $9 million due primarily to reduced maintenance activities as more work was devoted to capital projects.

·      Organizational restructuring charges of $15 million were partially offset by lower labor expenses of $11 million.

·      Employee benefits increased $37 million as a result of higher pension costs.

·      Storm-related costs were $6 million lower than in the third quarter of 2008.
 
·      Amortization of regulatory assets decreased $19 million due primarily to the cessation of transition cost amortization for OE and TE, partially offset by higher PJM
       transmission cost amortization in the third quarter of 2009.

·     The deferral of new regulatory assets decreased by $76 million in the third quarter of 2009 principally due to the absence of PJM transmission cost deferrals in
       Pennsylvania and RCP distribution cost deferrals by the Ohio Companies.

·     Depreciation expense increased $13 million due to property additions since the third quarter of 2008.

·     General taxes decreased $9 million primarily due to lower gross receipts and excise taxes.

Other Expense –

Other expense increased $18 million in the third quarter of 2009 compared to the third quarter of 2008 due to higher interest expense of $16 million, reflecting $300 million of senior notes issuances by each of JCP&L and Met-Ed in January 2009, $300 million of senior notes by TE in April 2009, and $300 million of FMBs by CEI in August 2009, partially offset by lower investment income of $2 million (reduced loan balances to the regulated money pool).

 
81

 


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

Net income for this segment was $183 million in the third quarter of 2009 compared to $164 million in the same period of 2008. The $19 million increase in net income principally reflects an increase in investment income offset by a decrease in gross sales margins.

Revenues –

Total revenues decreased $139 million in the third quarter of 2009 primarily due to lower generation sales to the Ohio Companies, partially offset by higher non-affiliated retail generation sales volumes.

The decrease in total revenues resulted from the following sources:

   
Three Months
     
   
Ended September 30
 
Increase
 
Revenues By Type of Service
 
2009
 
2008
 
(Decrease)
 
   
(In millions)
 
Non-Affiliated Generation Sales:
             
Retail
 
$
232
 
$
171
 
$
61
 
Wholesale
   
212
   
210
   
2
 
Total Non-Affiliated Generation Sales
   
444
   
381
   
63
 
Affiliated Generation Sales
   
616
   
786
   
(170
)
Transmission
   
17
   
47
   
(30
)
Other
   
30
   
32
   
(2
)
Total Revenues
 
$
1,107
 
$
1,246
 
$
(139
)

The higher retail revenues reflect the acquisition of government aggregation programs in Ohio and the acquisition of new retail customer contracts in the MISO and PJM markets in the third quarter of 2009. FES has signed new government aggregation contracts with 50 communities that provide discounted generation prices to approximately 600,000 residential and small commercial customers. Higher non-affiliated wholesale revenues resulted from lower sales volumes and higher prices in the PJM market offset by lower prices in the MISO market.

The lower affiliated company generation revenues were due primarily to a decrease in sales volumes to the Ohio Companies partially offset by higher unit prices for sales to the Ohio Companies and higher sales volumes to the Pennsylvania Companies. While unit prices for each of the Pennsylvania Companies did not change, the mix of sales among the companies caused the composite price to decline. Subsequent to the Ohio Companies’ CBP, FES purchased additional tranches from other winning bidders and effective September 1, 2009, FES supplied 72% of the Ohio Companies’ PLR generation requirements. Prior to the CBP, FES supplied 100% of the Ohio Companies' PLR generation requirements.

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

Source of Change in Non-Affiliated Generation Revenues
 
Increase (Decrease)
 
   
(In millions)
 
Retail:
       
Effect of 10.7% increase in sales volumes
 
$
19
 
Change in prices
   
42
 
     
61
 
Wholesale:
       
Effect of 2.8% decrease in sales volumes
   
(6
)
Change in prices
   
8
 
     
2
 
Net Increase in Non-Affiliated Generation Revenues
 
$
63
 

Source of Change in Affiliated Generation Revenues
 
Increase (Decrease)
 
   
(In millions)
 
Ohio Companies:
       
Effect of 47.8% decrease in sales volumes
 
$
(297
)
Change in prices
   
115
 
     
(182
)
Pennsylvania Companies:
       
Effect of 12.2% increase in sales volumes
   
19
 
Change in prices
   
(7
)
     
12
 
Net Decrease in Affiliated Generation Revenues
 
$
(170
)
 
 
 
82

 

Transmission revenues decreased $30 million due primarily to reduced loads following the expiration of the government aggregation programs in Ohio at the end of 2008.

Expenses -

Total expenses decreased $21 million in the third quarter of 2009 due to the following factors:

·  
Fuel costs decreased $54 million due to decreased generation volumes ($109 million), partially offset by higher unit prices ($55 million).

·  
Purchased power costs decreased $16 million due primarily to lower volume requirements ($71 million), partially offset by higher unit costs ($55 million) resulting from higher capacity costs.

·  
Fossil operating costs decreased $14 million due to a reduction in contractor and material costs, resulting from FirstEnergy’s cost control initiatives.

·  
Nuclear operating costs decreased $12 million due primarily to lower labor and employee benefit expenses of $6 million and reductions in contractor costs of $5 million.

·  
Other operating expenses increased $32 million due primarily to increased intersegment billings for leasehold costs from the Ohio Companies and increased pension costs.

·  
Transmission expense increased $41 million due primarily to increased transmission costs in MISO of $24 million and higher congestion expenses in PJM of $15 million.

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

Other Expense –

Total other expense in the third quarter of 2009 was $149 million lower than the third quarter of 2008, primarily due to a $146 million increase in earnings from nuclear decommissioning trust investments and a $3 million decrease in interest expense (net of capitalized interest).

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

Net income for this segment decreased $10 million to $9 million in the third quarter of 2009 from $19 million in the same period of 2008. Higher purchased power costs were partially offset by higher generation revenues and lower operating expenses.

Revenues –

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

   
Three Months
       
   
Ended September 30
 
Increase
 
Revenues by Type of Service
 
2009
 
2008
 
(Decrease)
 
   
(In millions)
 
Generation sales:
                   
Retail
 
$
726
 
$
675
 
$
51
 
Wholesale
   
-
   
4
   
(4
)
Total generation sales
   
726
   
679
   
47
 
Transmission
   
11
   
134
   
(123
)
Other
   
2
   
-
   
2
 
Total Revenues
 
$
739
 
$
813
 
$
(74
)


 
83

 


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

Source of Change in Retail Generation Revenues
 
Increase
(Decrease)
 
   
(In millions)
 
    Effect of 17% decrease in sales volumes
 
$
(116
)
Change in prices
   
167
 
 Total Increase in Retail Generation Revenues
 
$
51
 

The decrease in generation sales volumes was primarily due to increased customer shopping resulting from certain government aggregation programs in Ohio, lower weather-related usage and economic conditions in the Ohio Companies’ service territory. Average prices increased primarily due to the result of the Ohio Companies' CBP. Effective June 1, 2009, the transmission tariff ended and the recovery of transmission costs was included in the generation rate established under the CBP.

Decreased transmission revenue of $123 million resulted from the termination of the transmission tariff (as discussed above), reduced MISO revenues and lower sales volumes. Prior to June 1, 2009, the difference between transmission revenues and transmission costs incurred was deferred, resulting in no material impact to current period earnings.

Expenses -

Purchased power costs were $91 million higher due primarily to higher unit costs, partially offset by a decrease in volumes. The factors contributing to the higher costs are summarized in the following table:

Source of Change in Purchased Power
 
Increase
(Decrease)
 
   
(In millions)
 
         
Change due to increased unit costs
 
$
194
 
Change due to decreased volumes
   
(103
)
   
$
91
 

The decrease in purchased volumes was due to the lower retail generation sales requirements described above. The higher unit costs reflect the results of the Ohio Companies' CBP for retail customers during the third quarter of 2009 (see Regulatory Matters – Ohio).

Other operating expenses decreased $119 million due to lower MISO transmission-related expenses (effective June 1, 2009 transmission costs are paid by the generation suppliers) and increased intersegment credits related to the Ohio Companies' generation leasehold interests. The amortization of regulatory assets decreased by $29 million in the third quarter of 2009 due primarily to lower MISO transmission cost amortization.

 
84

 


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

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

               
Ohio
             
   
Energy
   
Competitive
   
Transitional
   
Other and
       
   
Delivery
   
Energy
   
Generation
   
Reconciling
   
FirstEnergy
 
First Nine Months 2009 Financial Results
 
Services
   
Services
   
Services
   
Adjustments
   
Consolidated
 
   
(In millions)
 
Revenues:
                             
External
                             
Electric
  $ 5,823     $ 929     $ 2,499     $ -     $ 9,251  
Other
    413       400       20       (71 )     762  
Internal
    -       2,349       -       (2,349 )     -  
Total Revenues
    6,236       3,678       2,519       (2,420 )     10,013  
                                         
Expenses:
                                       
Fuel
    -       890       -       -       890  
Purchased power
    2,853       551       2,425       (2,349 )     3,480  
Other operating expenses
    1,167       1,001       22       (87 )     2,103  
Provision for depreciation
    331       201       -       18       550  
Amortization of regulatory assets
    791       -       112       -       903  
Deferral of new regulatory assets
    -       -       (136 )     -       (136 )
General taxes
    480       84       6       17       587  
Total Expenses
    5,622       2,727       2,429       (2,401 )     8,377  
                                         
Operating Income
    614       951       90       (19 )     1,636  
Other Income (Expense):
                                       
Investment income
    110       136       1       (40 )     207  
Interest expense
    (343 )     (106 )     -       (306 )     (755 )
Capitalized interest
    3       42       -       51       96  
Total Other Expense
    (230 )     72       1       (295 )     (452 )
                                         
Income Before Income Taxes
    384       1,023       91       (314 )     1,184  
Income taxes
    154       409       36       (169 )     430  
Net Income
    230       614       55       (145 )     754  
Less: Noncontrolling interest income (loss)
    -       -       -       (14 )     (14 )
Earnings available to FirstEnergy Corp.
  $ 230     $ 614     $ 55     $ (131 )   $ 768  


 
85

 

 
               
Ohio
             
   
Energy
   
Competitive
   
Transitional
   
Other and
       
   
Delivery
   
Energy
   
Generation
   
Reconciling
   
FirstEnergy
 
First Nine Months 2008 Financial Results
 
Services
   
Services
   
Services
   
Adjustments
   
Consolidated
 
   
(In millions)
 
Revenues:
                             
External
                             
Electric
  $ 6,567     $ 994     $ 2,142     $ -     $ 9,703  
Other
    484       170       61       8       723  
Internal
    -       2,266       -       (2,266 )     -  
Total Revenues
    7,051       3,430       2,203       (2,258 )     10,426  
                                         
Expenses:
                                       
Fuel
    1       999       -       -       1,000  
Purchased power
    3,228       648       1,766       (2,266 )     3,376  
Other operating expenses
    1,288       906       268       (88 )     2,374  
Provision for depreciation
    309       179       -       12       500  
Amortization of regulatory assets
    747       -       48       -       795  
Deferral of new regulatory assets
    (274 )     -       13       -       (261 )
General taxes
    491       82       4       19       596  
Total Expenses
    5,790       2,814       2,099       (2,323 )     8,380  
                                         
Operating Income
    1,261       616       104       65       2,046  
Other Income (Expense):
                                       
Investment income
    133       (1 )     1       (60 )     73  
Interest expense
    (305 )     (116 )     (1 )     (137 )     (559 )
Capitalized interest
    2       30       -       4       36  
Total Other Expense
    (170 )     (87 )     -       (193 )     (450 )
                                         
Income Before Income Taxes
    1,091       529       104       (128 )     1,596  
Income taxes
    436       212       42       (105 )     585  
Net Income
    655       317       62       (23 )     1,011  
Less: Noncontrolling interest income
    -       -       -       1       1  
Earnings available to FirstEnergy Corp.
  $ 655     $ 317     $ 62     $ (24 )   $ 1,010  
                                         
                                         
Changes Between First Nine Months 2009
                                 
and First Nine Months 2008
                                       
Financial Results Increase (Decrease)
                                       
                                         
Revenues:
                                       
External
                                       
Electric
  $ (744 )   $ (65 )   $ 357     $ -     $ (452 )
Other
    (71 )     230       (41 )     (79 )     39  
Internal
    -       83       -       (83 )     -  
Total Revenues
    (815 )     248       316       (162 )     (413 )
                                         
Expenses:
                                       
Fuel
    (1 )     (109 )     -       -       (110 )
Purchased power
    (375 )     (97 )     659       (83 )     104  
Other operating expenses
    (121 )     95       (246 )     1       (271 )
Provision for depreciation
    22       22       -       6       50  
Amortization of regulatory assets
    44       -       64       -       108  
Deferral of new regulatory assets
    274       -       (149 )     -       125  
General taxes
    (11 )     2       2       (2 )     (9 )
Total Expenses
    (168 )     (87 )     330       (78 )     (3 )
                                         
Operating Income
    (647 )     335       (14 )     (84 )     (410 )
Other Income (Expense):
                                       
Investment income
    (23 )     137       -       20       134  
Interest expense
    (38 )     10       1       (169 )     (196 )
Capitalized interest
    1       12       -       47       60  
Total Other Expense
    (60 )     159       1       (102 )     (2 )
                                         
Income Before Income Taxes
    (707 )     494       (13 )     (186 )     (412 )
Income taxes
    (282 )     197       (6 )     (64 )     (155 )
Net Income
    (425 )     297       (7 )     (122 )     (257 )
Less: Noncontrolling interest income
    -       -       -       (15 )     (15 )
Earnings available to FirstEnergy Corp.
  $ (425 )   $ 297     $ (7 )   $ (107 )   $ (242 )


 
86

 

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

Net income decreased $425 million to $230 million in the first nine months of 2009 compared to $655 million in the first nine months of 2008, primarily due to lower revenues and decreased deferrals of new regulatory assets, partially offset by lower purchased power and other operating expenses.

Revenues –

The decrease in total revenues resulted from the following sources:

   
Nine Months
     
   
Ended September 30
 
Increase
 
Revenues by Type of Service
 
2009
 
2008
 
(Decrease)
 
   
(In millions)
 
Distribution services
 
$
2,578
 
$
2,974
 
$
(396
)
Generation sales:
                   
   Retail
   
2,355
   
2,548
   
(193
)
   Wholesale
   
545
   
758
   
(213
)
Total generation sales
   
2,900
   
3,306
   
(406
)
Transmission
   
616
   
633
   
(17
)
Other
   
142
   
138
   
4
 
Total Revenues
 
$
6,236
 
$
7,051
 
$
(815
)

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

Electric Distribution KWH Deliveries
     
Residential
   
(3.7)
%
Commercial
   
(4.7)
%
Industrial
   
(18.0)
%
Total Distribution KWH Deliveries
   
(8.6)
%

The lower revenues from distribution deliveries were due to reductions in sales volume and lower unit prices. The decreases in distribution deliveries to commercial and industrial customers were primarily due to economic conditions in FirstEnergy's service territories. In the industrial sector, KWH deliveries declined due to major automotive customers (25.0%) and steel customers (44.4%). Transition charges for OE and TE that ceased effective January 1, 2009 with the full recovery of related costs and the transition rate reduction for CEI effective June 1, 2009, were partially offset by PUCO-approved distribution rate increases (see Regulatory Matters – Ohio).

The following table summarizes the price and volume factors contributing to the $406 million decrease in generation revenues in the first nine months of 2009 compared to the same period of 2008:

   
Increase
 
Sources of Change in Generation Revenues
 
(Decrease)
 
   
(In millions)
 
Retail:
       
  Effect of 8% decrease in sales volumes
 
$
(208
)
  Change in prices
   
15
 
     
(193
)
Wholesale:
       
  Effect of 14% decrease in sales volumes
   
(108
)
  Change in prices
   
(105
)
     
(213
)
Net Decrease in Generation Revenues
 
$
(406
)

The decrease in retail generation sales volumes was primarily due to weaker economic conditions and reduced weather-related usage. Cooling degree days decreased by 17% in the first nine months of 2009, while heating degree days increased by 3% compared to the same period last year. The increase in retail generation prices during the first nine months of 2009 was due to higher generation rates for JCP&L and Penn under their power procurement processes. Wholesale generation sales decreased principally as a result of JCP&L selling less available power from NUGs due to the termination of a NUG purchase contract in October 2008. The decrease in wholesale prices reflected lower spot market prices in PJM.

 
87

 


Transmission revenues decreased $17 million primarily due to lower PJM transmission revenues partially offset by higher transmission rates for Met-Ed and Penelec resulting from the annual updates to their TSC riders.

Expenses –

Total expenses decreased by $168 million due to the following:

 
·
Purchased power costs were $375 million lower in the first nine months of 2009 due to reduced volumes and an increase in the amount of NUG costs deferred, partially offset by higher unit costs. The increased unit costs primarily reflected the effect of higher JCP&L costs resulting from its BGS auction process. The following table summarizes the sources of changes in purchased power costs:

Source of Change in Purchased Power
 
Increase
(Decrease)
 
   
(In millions)
 
Purchases from non-affiliates:
       
Change due to increased unit costs
 
$
196
 
Change due to decreased volumes
   
(471
)
     
(275
)
Purchases from FES:
       
Change due to decreased unit costs
   
(23
)
Change due to increased volumes
   
57
 
     
34
 
         
Increase in NUG costs deferred
   
(134
)
Net Decrease in Purchased Power Costs
 
$
(375
)

·  PJM transmission expenses were lower by $164 million, resulting primarily from reduced volumes and lower congestion costs.

·  Organizational restructuring charges of $32 million and increased pension costs of $102 million were partially offset by lower labor expenses of $50 million.
 
·  An increase in other operating expense of $32 million resulted from recognition of economic development and energy efficiency obligations in accordance with
        the PUCO-approved ESP.

·  Contractor and material expenses decreased $48 million, reflecting more costs dedicated to capital projects compared to the prior year.

·  Storm related costs were $6 million lower in the first nine months of 2009.

·  Lower general business expenses of $18 million reflected FirstEnergy’s cost control initiatives.

·  A $44 million increase in the amortization of regulatory assets was due primarily to the ESP-related impairment of CEI’s regulatory assets and PJM transmission
       cost amortization in the first nine months of 2009, partially offset by the cessation of transition cost amortization for OE and TE.
 
·  A $274 million decrease in the deferral of new regulatory assets was principally due to the absence in 2009 of PJM transmission cost deferrals and RCP distribution
       cost deferrals by the Ohio Companies.
 
·  Depreciation expense increased $22 million due to property additions since the third quarter of 2008.

·  General taxes decreased $11 million due to lower gross receipts taxes.

Other Expense –

Other expense increased $60 million in the first nine months of 2009 compared to 2008. Lower investment income of $23 million resulted primarily from repaid notes receivable from affiliates since the third quarter of 2008. Higher interest expense (net of capitalized interest) of $38 million resulted from debt issuances described above under Financing Activities.

 
88

 


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

Net income increased to $614 million in the first nine months of 2009 compared to $317 million in the same period of 2008. The increase in net income includes FGCO's $252 million gain from the sale of a 9% participation interest in OVEC ($158 million after tax), an increase in investment income, and an increase in gross sales margins.

Revenues –

Total revenues increased $248 million in the first nine months of 2009 compared to the same period in 2008. This increase primarily resulted from the OVEC sale and higher unit prices on affiliated generation sales to the Ohio Companies and non-affiliated customers, partially offset by lower sales volumes.

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

   
Nine Months
       
   
Ended September 30
 
Increase
 
Revenues by Type of Service
 
2009
 
2008
 
(Decrease)
 
   
(In millions)
 
Non-Affiliated Generation Sales:
                   
Retail
 
$
406
 
$
485
 
$
(79
)
Wholesale
   
523
   
509
   
14
 
Total Non-Affiliated Generation Sales
   
929
   
994
   
(65
)
Affiliated Generation Sales
   
2,349
   
2,266
   
83
 
Transmission
   
57
   
113
   
(56
)
Sale of OVEC participation interest
   
252
   
-
   
252
 
Other
   
91
   
57
   
34
 
Total Revenues
 
$
3,678
 
$
3,430
 
$
248
 

The lower retail revenues resulted from the expiration of government aggregation programs in Ohio at the end of 2008 that were supplied by FES, partially offset by increased revenue in both the PJM and MISO markets. The increase in MISO retail revenue is primarily the result of the acquisition of new customers and higher unit prices. The increase in PJM retail revenue resulted from the acquisition of new customers, higher sales volumes and unit prices. FES has signed new government aggregation contracts with 50 communities in Ohio that will provide discounted generation prices to approximately 600,000 residential and small commercial customers. Higher non-affiliated wholesale revenues resulted from higher capacity prices in PJM offset by decreased spot market prices in PJM and increased sales volumes and favorable settlements on hedged transactions in MISO, offset by decreased sales volumes in PJM.

The increased affiliated company generation revenues were due to higher unit prices to the Ohio Companies and increased sales volumes to Met-Ed and Penelec, partially offset by lower sales volumes to the Ohio Companies. The higher unit prices reflected the results of the Ohio Companies' power procurement processes in the first half of 2009 (see Regulatory Matters – Ohio). The higher sales to the Pennsylvania Companies were due to increased Met-Ed and Penelec generation sales requirements supplied by FES versus other suppliers, partially offset by lower sales to Penn due to decreased default service requirements in the first nine months of 2009 compared to the first nine months of 2008.

In the first quarter of 2009, FES supplied approximately 75% of the Ohio Companies’ power requirements as one of four winning bidders in the Ohio Companies' RFP process. In the second quarter of 2009, FES supplied 100% of the power for the Ohio Companies’ PLR service in April and May 2009, and approximately 56% of the Ohio Companies' supply needs in June 2009. Subsequent to the Ohio Companies’ CBP, FES purchased additional tranches from other winning bidders. Effective September 1, 2009, FES supplied 72% of the Ohio Companies’ PLR generation requirements. Prior to the CBP, FES supplied 100% of the Ohio Companies' PLR generation requirements.

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

   
Increase
 
Source of Change in Non-Affiliated Generation Revenues
 
(Decrease)
 
   
(In millions)
 
Retail:
       
Effect of 34.3% decrease in sales volumes
 
$
(166
)
Change in prices
   
87
 
     
(79
)
Wholesale:
       
Effect of 3.5% decrease in sales volumes
   
(18
)
Change in prices
   
32
 
     
14
 
Net Decrease in Non-Affiliated Generation Revenues
 
$
(65
)

 
89

 



   
Increase
 
Source of Change in Affiliated Generation Revenues
 
(Decrease)
 
   
(In millions)
 
Ohio Companies:
       
Effect of 28.9% decrease in sales volumes
 
$
(508)
 
Change in prices
   
557
 
     
49
 
Pennsylvania Companies:
       
Effect of 11.1% increase in sales volumes
   
57
 
Change in prices
   
(23)
 
     
34
 
Net Increase in Affiliated Generation Revenues
 
$
83
 

Transmission revenues decreased $56 million due primarily to reduced loads following the expiration of the government aggregation programs in Ohio at the end of 2008. Other revenue increased $34 million primarily due to rental income associated with NGC's acquisition of equity interests in the Perry and Beaver Valley Unit 2 leases.

Expenses -

Total expenses decreased $87 million in the first nine months of 2009 due to the following factors:

·  Fuel costs decreased $109 million due to lower generation volumes ($227 million), partially offset by higher unit prices ($118 million).
 
·  Purchased power costs decreased $97 million due to lower volume ($170 million), partially offset by higher unit prices ($73 million) that resulted primarily from
       higher capacity costs.

·  Fossil operating costs decreased $46 million due primarily to a reduction in contractor and material costs  ($38 million) and more labor dedicated to capital projects
       ($6 million) compared to the prior year.

·  Nuclear operating costs decreased $4 million in the first nine months of 2009 as lower labor and employee benefits expense was partially offset by the cost of an
       additional refueling outage during the 2009 period.

·  Other expense increased $83 million due primarily to increased intersegment billings for leasehold costs from the Ohio Companies and higher pension costs.

·  Transmission expense increased $64 million due primarily to increased net congestion in PJM and higher loss expenses in MISO and PJM.

·  Higher depreciation expense of $22 million was due to NGC's increased ownership interest in Beaver Valley Unit 2 and Perry.

Other Expense –

Total other expense in the first nine months of 2009 was $159 million lower than the first nine months of 2008, primarily due to a $137 million increase in earnings from nuclear decommissioning trust investments and a decline in interest expense (net of capitalized interest) of $22 million due to the repayment of notes payable to affiliates.

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

Net income for this segment decreased $7 million to $55 million in the first nine months of 2009 from $62 million in the same period of 2008. Higher purchased power expenses were partially offset by higher generation revenues and increased deferrals of regulatory assets.

 
90

 

Revenues –

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

   
Nine Months Ended
     
   
September 30
     
Revenues by Type of Service
 
2009
 
2008
 
Increase (Decrease)
 
   
(In millions)
 
Generation sales:
             
Retail
 
$
2,323
 
$
1,868
 
$
455
 
Wholesale
   
-
   
9
   
(9
)
Total generation sales
   
2,323
   
1,877
   
446
 
Transmission
   
192
   
319
   
(127
)
Other
   
4
   
7
   
(3
)
Total Revenues
 
$
2,519
 
$
2,203
 
$
316
 

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 3% decrease in sales volumes
 
$
(52
)
Change in prices
   
507
 
 Net Increase in Retail Generation Revenues
 
$
455
 







The decrease in generation sales volume in the first nine months of 2009 was primarily due to milder weather and economic conditions in the Ohio Companies' service territory. Average price increases reflect an increase in the Ohio Companies' fuel cost recovery riders that were in effect from January through May 2009. In addition, effective June 1, 2009, the transmission tariff ended with the recovery of transmission costs now included in the generation rate established under the Ohio Companies' CBP.

Decreased transmission revenue of $127 million resulted primarily from the termination of the transmission tariff effective June 1, 2009, lower MISO transmission related revenues and decreased sales volumes.

Expenses -

Purchased power costs were $659 million higher due primarily to higher unit costs for power. The factors contributing to the higher costs are summarized in the following table:

Source of Change in Purchased Power
 
Increase
(Decrease)
 
   
(In millions)
 
         
Change due to increased unit costs
 
$
712
 
Change due to decreased volumes
   
(53
)
   
$
659
 

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

Other operating expenses decreased $246 million due primarily to lower MISO transmission expenses and higher intersegment cost reimbursements related to the Ohio Companies' generation leasehold interests. The amortization of regulatory assets increased by $64 million in the first nine months of 2009 due primarily to increased MISO transmission cost amortization. The deferral of new regulatory assets increased by $149 million due to CEI’s deferral of purchased power costs as approved by the PUCO.

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

Financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $107 million decrease in FirstEnergy's net income in the first nine months of 2009 compared to the same period in 2008. The decrease resulted primarily from debt redemption costs ($90 million, net of taxes) and  the absence of the gain on the 2008 sale of telecommunication assets ($19 million, net of taxes).

 
91

 

CAPITAL RESOURCES AND LIQUIDITY

FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligations and those of its subsidiaries. FirstEnergy's business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. During 2009 and in subsequent years, FirstEnergy expects to satisfy these requirements with a combination of cash from operations and funds from the capital markets as market conditions warrant. FirstEnergy also expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.

As of September 30, 2009, FirstEnergy's net deficit in working capital (current assets less current liabilities) was principally due to short-term borrowings ($1.7 billion) and the classification of certain variable interest rate PCRBs as currently payable long-term debt. Currently payable long-term debt as of September 30, 2009, included the following (in millions):


Currently Payable Long-term Debt
     
PCRBs supported by bank LOCs(1)
 
$
1,553
 
FGCO and NGC unsecured PCRBs(1)
 
97
 
CEI secured notes(2)
 
150
 
Met-Ed unsecured notes(3)
 
100
 
Penelec unsecured notes(4)
 
35
 
NGC collateralized lease obligation bonds
 
44
 
Sinking fund requirements
 
41
 
   
$
2,020
 
       
(1)  Interest rate mode permits individual debt holders to put the respective debt back to the issuer prior to maturity.
(2)  Mature in November 2009.
(3)  Mature in March 2010.
(4)  Mature in August 2010.
.
 

 
Short-Term Borrowings

FirstEnergy had approximately $1.7 billion of short-term borrowings as of September 30, 2009 and $2.4 billion as of December 31, 2008. FirstEnergy, along with certain of its subsidiaries, has access to $2.75 billion of short-term financing under a revolving credit facility that expires in August 2012. A total of 25 banks participate in the facility, with no one bank having more than 7.3% of the total commitment. As of October 30, 2009, FirstEnergy had $120 million of bank credit facilities in addition to the $2.75 billion revolving credit facility. Also, an aggregate of $550 million of accounts receivable financing facilities through the Ohio and Pennsylvania Companies may be accessed to meet working capital requirements and for other general corporate purposes. In August 2009, FGCO and FES cancelled an unused $300 million secured term loan facility with Credit Suisse. FirstEnergy's available liquidity as of October 30, 2009, is summarized in the following table:

Company
 
Type
 
Maturity
 
Commitment
 
Available
Liquidity as of
October 30, 2009
 
           
(In millions)
 
FirstEnergy(1)
 
Revolving
 
Aug. 2012
 
$
2,750
 
$
1,334
 
FirstEnergy and FES
 
Bank lines
 
Various(2)
   
120
   
20
 
Ohio and Pennsylvania Companies
 
Receivables financing
 
Various(3)
   
550
   
306
 
       
Subtotal
 
$
3,420
 
$
1,660
 
       
Cash
   
-
   
748
 
       
Total
 
$
3,420
 
$
2,408
 
                       
(1) FirstEnergy Corp. and subsidiary borrowers.
(2) $100 million expires March 31, 2011; $20 million uncommitted line of credit has no expiration date.
(3) $180 million expires December 18, 2009; $370 million expires February 22, 2010.
 

Revolving Credit Facility

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

 
92

 


The following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of September 30, 2009:

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

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

The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of September 30, 2009, FirstEnergy's and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:

Borrower
   
FirstEnergy(1)
 
61.6
%
FES
 
54.2
%
OE
 
46.6
%
Penn
 
32.9
%
CEI
 
59.3
%
TE
 
53.9
%
JCP&L
 
34.9
%
Met-Ed
 
41.6
%
Penelec
 
54.1
%

 (1)
As of September 30, 2009, FirstEnergy could issue additional debt of approximately $2.4 billion, or recognize a reduction in equity of approximately $1.3 billion, and remain within the limitations of the financial covenants required by its revolving credit facility.
 

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.

 
93

 


FirstEnergy Money Pools

FirstEnergy's regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy's unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first nine months of 2009 was 0.78% for the regulated companies' money pool and 0.96% for the unregulated companies' money pool.

Pollution Control Revenue Bonds

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

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

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

In February 2009, holders of approximately $434 million principal of LOC-supported PCRBs of OE and NGC were notified that the applicable Wachovia Bank LOCs were to expire on March 18, 2009. As a result, these PCRBs were subject to mandatory purchase at a price equal to the principal amount, plus accrued and unpaid interest, which OE and NGC funded through short-term borrowings. In March 2009, FGCO remarketed $100 million of those PCRBs, which were previously held by OE. During the second quarter of 2009, NGC remarketed the remaining $334 million of PCRBs, of which $170 million was remarketed in fixed interest rate modes and secured by FMBs, thereby eliminating the need for third-party credit support. During the second quarter of 2009, FGCO remarketed approximately $248 million of PCRBs supported by LOCs set to expire in June 2009. These PCRBs were also remarketed in fixed interest rate modes and secured by FMBs, thereby eliminating the need for third-party credit support. Also, in June 2009, FGCO and NGC delivered FMBs to certain LOC banks listed above in connection with amendments to existing LOC and reimbursement agreements supporting twelve other series of PCRBs as described below and pledged FMBs to the applicable trustee under six separate series of PCRBs. On August 14, 2009, $177 million of non-LOC supported fixed rate PCRBs were issued and sold on behalf of FGCO to pay a portion of the cost of acquiring, constructing and installing air quality facilities at its W.H. Sammis Generating Station. On October 1, 2009, FGCO and NGC repurchased approximately $52.1 million and $29.6 million of variable rate PCRBs, respectively. These PCRBs are secured by a corresponding series of FMBs until December 31, 2009. Subject to market conditions, FGCO and NGC plan to remarket the purchased PCRBs in fixed-rate mode in the near future.


 
94

 


Long-Term Debt Capacity

As of September 30, 2009, the Ohio Companies and Penn had the aggregate capability to issue approximately $1.5 billion of additional FMBs on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMBs by the Ohio Companies is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMBs) supporting pollution control notes or similar obligations, or as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE and CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $164 million and $32 million, respectively, as of September 30, 2009. In April 2009, TE issued $300 million of new senior secured notes backed by FMBs. Concurrently with that issuance, and in order to satisfy the limitation on secured debt under its senior note indenture, TE issued an additional $300 million of FMBs to secure $300 million of its outstanding unsecured senior notes originally issued in November 2006. As a result, the provisions for TE to incur additional secured debt do not apply. In August 2009 CEI issued $300 million of FMB. CEI restricted $150 million of the proceeds to fund the redemption of $150 million of secured notes due in November 2009.

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

In June 2009, a new FMB indenture became effective for NGC. Based upon NGC’s FMB indenture, net earnings and available bondable property additions, NGC had the capability to issue $264 million of additional FMBs as of September 30, 2009. On June 16, 2009, NGC issued a total of approximately $487.5 million principal amount of FMBs, of which $107.5 million related to one new refunding series of PCRBs and approximately $380 million related to amendments to existing LOC and reimbursement agreements supporting seven other series of PCRBs. In addition, on June 16, 2009, NGC issued an FMB in a principal amount of up to $500 million in connection with NGC's delivery of a Surplus Margin Guaranty of FES’ obligations to post and maintain collateral under the Power Supply Agreement entered into by FES with the Ohio Companies as a result of the May 13-14, 2009 CBP auction. On June 30, 2009, NGC issued a total of approximately $273.3 million principal amount of FMBs, of which approximately $92 million related to three existing series of PCRBs ($29.6 million repurchased in October 2009, as described above) and approximately $181.3 million related to amendments to existing LOC and reimbursement agreements supporting three other series of PCRBs.

Met-Ed and Penelec had the capability to issue secured debt of approximately $376 million and $319 million, respectively, under provisions of their senior note indentures as of September 30, 2009.

FirstEnergy's access to capital markets and costs of financing are influenced by the ratings of its securities. The following table displays FirstEnergy's, FES' and the Utilities' securities ratings as of September 30, 2009. On August 3, 2009 Moody’s upgraded the majority of senior secured debt ratings of investment grade regulated utilities by one notch. S&P's and Moody's outlook for FirstEnergy and its subsidiaries remains "stable."

Issuer
   
Securities
   
S&P
   
Moody's
             
FirstEnergy
 
Senior unsecured
 
BBB-
 
Baa3
             
FES
 
Senior secured
 
BBB
 
Baa1
   
Senior unsecured
 
BBB
 
Baa2
             
OE
 
Senior secured
 
BBB+
 
A3
   
Senior unsecured
 
BBB
 
Baa2
             
Penn
 
Senior secured
 
A-
 
A3
             
CEI
 
Senior secured
 
BBB+
 
Baa1
   
Senior unsecured
 
BBB
 
Baa3
             
TE
 
Senior secured
 
BBB+
 
Baa1
   
Senior unsecured
 
BBB
 
Baa3
             
JCP&L
 
Senior unsecured
 
BBB
 
Baa2
             
Met-Ed
 
Senior unsecured
 
BBB
 
Baa2
             
Penelec
 
Senior unsecured
 
BBB
 
Baa2

 
95

 


On September 22, 2008, FirstEnergy, along with the Shelf Registrants, filed an automatically effective shelf registration statement with the SEC for an unspecified number and amount of securities to be offered thereon. The shelf registration provides FirstEnergy the flexibility to issue and sell various types of securities, including common stock, preferred stock, debt securities, warrants, share purchase contracts, and share purchase units. The Shelf Registrants have utilized, and may in the future utilize, the shelf registration statement to offer and sell unsecured and, in some cases, secured debt securities.

Changes in Cash Position

As of September 30, 2009, FirstEnergy had $838 million in cash and cash equivalents compared to $545 million as of December 31, 2008. Cash and cash equivalents consist of unrestricted, highly liquid instruments with an original or remaining maturity of three months or less. As of September 30, 2009, approximately $794 million of cash and cash equivalents represented temporary overnight deposits. As of September 30, 2009 and December 31, 2008, FirstEnergy had $171 million and $17 million, respectively, of restricted cash included in other current assets on the Consolidated Balance Sheet.

During the first nine months of 2009, FirstEnergy received $621 million of cash from dividends and equity repurchases from its subsidiaries and paid $503 million in cash dividends to common shareholders. With the exception of Met-Ed, which is currently in an accumulated deficit position, there are no material restrictions on the payment of cash dividends by FirstEnergy’s subsidiaries. In addition to paying dividends from retained earnings, each of FirstEnergy’s electric utility subsidiaries has authorization from the FERC to pay cash dividends from paid-in capital accounts, as long as the subsidiary’s debt to total capitalization ratio (without consideration of retained earnings) remains below 65%. CEI and TE are the only utility subsidiaries currently precluded from that action.

Cash Flows From Operating Activities

FirstEnergy's consolidated net cash from operating activities is provided primarily by its competitive energy services and energy delivery services businesses (see Results of Operations above). Net cash provided from operating activities increased by $33 million during the first nine months of 2009 compared to the comparable period in 2008, as summarized in the following table:

   
Nine Months Ended
September 30
       
 
Operating Cash Flows
 
2009
 
2008
 
Increase (Decrease)
 
   
(In millions)
 
Net income
 
$
754
 
$
1,011
 
$
(257
)
Non-cash charges and other adjustments
   
1,755
   
1,033
   
722
 
Pension trust contribution
   
(500)
   
-
   
(500
)
Working capital and other
   
(545)
   
(613
)
 
68
 
   
$
1,464
 
$
1,431
 
$
33
 

The increase in non-cash charges and other adjustments is primarily due to higher net amortization of regulatory assets ($233 million), including CEI’s $216 million regulatory asset impairment, changes in accrued compensation and retirement benefits ($147 million), changes in deferred income taxes and investment tax credits, net ($143 million), and an increase in the provision for depreciation ($50 million). Also included in non-cash charges and other adjustments was a $142 million charge relating to debt redemptions in 2009, of which $122 million was related primarily to the premium paid and included as a cash outflow in financing activities. The changes in working capital and other primarily resulted from a $73 million decrease in stock-based compensation payments and an increase in other accrued expenses principally associated with the implementation of the Ohio Companies’ Amended ESP.

Cash Flows From Financing Activities

In the first nine months of 2009, cash provided from financing activities was $617 million compared to $911 million in the first nine months of 2008. The decrease was primarily due to increased long-term debt redemptions and reduced short-term borrowings, partially offset by increased long-term debt issuances in the first nine months of 2009. The increased long-term debt redemptions were primarily due to the $1.2 billion tender offer completed by FirstEnergy in September 2009, including approximately $122 million of premiums and redemption expenses paid. The following table summarizes security issuances (net of any discounts) and redemptions, including premiums paid to debt holders as a result of the tender offer.

 
96

 


   
Nine Months Ended
 
   
September 30
 
Securities Issued or Redeemed
 
2009
 
2008
 
   
(In millions)
 
New issues
             
First mortgage bonds
 
$
398
 
$
-
 
Pollution control notes
   
859
   
611
 
Senior secured notes
   
297
   
-
 
Unsecured notes
   
2,597
   
20
 
   
$
4,151
 
$
631
 
               
Redemptions
             
First mortgage bonds
 
$
-
 
$
1
 
Pollution control notes
   
687
   
534
 
Senior secured notes
   
54
   
23
 
Unsecured notes*
   
1,472
   
175
 
   
$
2,213
 
$
733
 
               
Short-term borrowings, net
 
$
(764)
 
$
1,489
 
               
* Including premiums and redemption expenses paid of $122 million.
 

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

Issuing Company
 
Issue
Date
 
Principal
(in millions)
 
 
Type
 
 
Maturity
 
 
Use of Proceeds
                     
Met-Ed*
 
01/20/2009
 
$300
 
7.70% Senior Notes
 
2019
 
Repay short-term borrowings
                     
JCP&L*
 
01/27/2009
 
$300
 
7.35% Senior Notes
 
2019
 
Repay short-term borrowings, fund capital expenditures and other general purposes
                     
TE*
 
04/24/2009
 
$300
 
7.25% Senior
Secured Notes
 
2020
 
Repay short-term borrowings, fund capital expenditures and other general purposes
                     
Penn
 
06/30/2009
 
$100
 
6.09% FMB
 
2022
 
Fund capital expenditures and repurchase
equity from OE
                     
FES
 
08/07/2009
 
$400
$600
$500
 
4.80% Senior Notes
6.05% Senior Notes
6.80% Senior Notes
 
2015
2021
2039
 
Repay short-term borrowings and other
general purposes
                     
CEI*
 
08/18/2009
 
$300
 
5.50% FMB
 
2024
 
$150M placed with trustee for future debt redemption, repay short-term borrowings
and other general purposes
                     
Penelec*
 
9/30/2009
 
$250
$250
 
5.20% Senior Notes
6.15% Senior Notes
 
2020
2038
 
Repay short-term borrowings
                     
* Issued under the shelf registration statement referenced above.


On October 30, 2009, Penelec provided notice for early redemption of its $35 million aggregate principal 7.77% Notes due August 2, 2010. The Notes are scheduled to be redeemed on November 30, 2009 with a make-whole redemption price.

Cash Flows From Investing Activities

Net cash flows used in investing activities resulted primarily from property additions. Additions for the energy delivery services segment primarily represent expenditures related to transmission and distribution facilities. Capital spending by the competitive energy services segment is principally generation-related. The following table summarizes investing activities for the nine months ended September 30, 2009 and 2008 by business segment:

 
97

 


Summary of Cash Flows
 
Property
             
Provided from (Used for) Investing Activities
 
Additions
 
Investments
 
Other
 
Total
 
Sources (Uses)
 
(In millions)
 
Nine Months Ended September 30, 2009
                 
Energy delivery services
 
$
(524
)
$
(121
)
$
(35
)
$
(680
)
Competitive energy services
   
(893
)
 
(6
)
 
(21
)
 
(920
)
Other
   
(133
)
 
-
   
(11
)
 
(144
)
Inter-Segment reconciling items
   
(25
)
 
(25
)
 
6
   
(44
)
Total
 
$
(1,575
)
$
(152
)
$
(61
)
$
(1,788
)
                           
Nine Months Ended September 30, 2008
                         
Energy delivery services
 
$
(621
)
$
33
 
$
(3
)
$
(591
)
Competitive energy services
   
(1,430
)
 
(13
)
 
(121
)
 
(1,564
)
Other
   
(106
)
 
57
   
(54
)
 
(103
)
Inter-Segment reconciling items
   
(20
)
 
(12
)
 
-
   
(32
)
Total
 
$
(2,177
)
$
65
 
$
(178
)
$
(2,290
)

Net cash used for investing activities in the first nine months of 2009 decreased by $502 million compared to the first nine months of 2008. The decrease was principally due to a $602 million decrease in property additions, which reflects lower AQC system expenditures and the absence in 2009 of the purchase of certain lessor equity interests in Beaver Valley Unit 2 and Perry, and the purchase of the partially-completed Fremont Energy Center. The decrease in property additions was partially offset by the absence in 2009 of cash proceeds from the sale of telecommunication assets in the first quarter of 2008 combined with increased restricted funds to be used for future debt redemptions.

During the last three months of 2009, capital requirements for property additions and capital leases are expected to be approximately $410 million, including approximately $65 million for nuclear fuel. FirstEnergy has additional requirements of approximately $164 million for maturing long-term debt during the remainder of 2009. These cash requirements are expected to be satisfied from a combination of internal cash, short-term credit arrangements and funds raised in the capital markets.

FirstEnergy's capital spending for the period 2009-2013 is expected to be approximately $8.0 billion (excluding nuclear fuel), of which approximately $1.7 billion applies to 2009. Investments for additional nuclear fuel during the 2009-2013 period are estimated to be approximately $1.3 billion, of which about $295 million applies to 2009. During the same period, FirstEnergy's nuclear fuel investments are expected to be reduced by approximately $1.0 billion and $130 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 September 30, 2009, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.1 billion, as summarized below:

 
98

 


   
Maximum
 
Guarantees and Other Assurances
 
Exposure
 
   
(In millions)
 
FirstEnergy Guarantees on Behalf of its Subsidiaries
     
Energy and Energy-Related Contracts (1)
 
$
385
 
LOC (long-term debt) – interest coverage (2)
   
6
 
FirstEnergy guarantee of OVEC obligations
   
300
 
Other (3)
   
296
 
     
987
 
         
Subsidiaries’ Guarantees
       
Energy and Energy-Related Contracts
   
54
 
LOC (long-term debt) – interest coverage (2)
   
6
 
FES’ guarantee of NGC’s nuclear property insurance
   
77
 
FES’ guarantee of FGCO’s sale and leaseback obligations
   
2,502
 
     
2,639
 
         
Surety Bonds
   
103
 
LOC (long-term debt) – interest coverage (2)
   
4
 
LOC (non-debt) (4)(5)
   
398
 
     
505
 
Total Guarantees and Other Assurances
 
$
4,131
 

 
(1)
Issued for open-ended terms, with a 10-day termination right by FirstEnergy.
 
(2)
Reflects the interest coverage portion of LOCs issued in support of floating rate
PCRBs with various maturities. The principal amount of floating-rate PCRBs of
$1.6 billion is reflected in currently payable long-term debt on FirstEnergy’s
consolidated balance sheets.
 
(3)
Includes guarantees of $80 million for nuclear decommissioning funding (see
Nuclear Plant Matters below) assurances and $161 million supporting OE’s sale
and leaseback arrangement.
 
(4)
Includes $58 million issued for various terms pursuant to LOC capacity available
under FirstEnergy’s revolving credit facility.
 
(5)
Includes approximately $206 million pledged in connection with the sale and l
easeback of Beaver Valley Unit 2 by OE and $134 million pledged in connection
with the sale and leaseback of Perry by OE.

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

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade to below investment grade or a “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of September 30, 2009, FirstEnergy’s maximum exposure under these collateral provisions was $616 million as shown below:

Collateral Provisions
 
FES
 
Utilities
 
Total
 
   
(In millions)
 
Credit rating downgrade to below investment grade
 
$
305
 
$
115
 
$
420
 
Acceleration of payment or funding obligation
   
80
   
63
   
143
 
Material adverse event
   
53
   
-
   
53
 
Total
 
$
438
 
$
178
 
$
616
 

Stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase the total potential amount to $699 million, consisting of $60 million due to “material adverse event” contractual clauses and $639 million due to a below investment grade credit rating.

 
99

 


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

In addition to guarantees and surety bonds, FES’ contracts, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions which require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ power portfolio as of September 30, 2009, and forward prices as of that date, FES had $183 million of outstanding collateral payments. Under a hypothetical adverse change in forward prices (15% decrease in the first 12 months and 20% decrease thereafter in prices), FES would be required to post an additional $45 million. Depending on the volume of forward contracts entered and future price movements, FES could be required to post significantly higher amounts for margining.

In connection with FES’ obligations to post and maintain collateral under the two-year PSA entered into by FES and the Ohio Companies following the CBP auction on May 13-14, 2009, NGC entered into a Surplus Margin Guaranty in the amount up to $500 million. The Surplus Margin Guaranty is secured by an NGC FMB issued in favor of the Ohio Companies.

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

OFF-BALANCE SHEET ARRANGEMENTS

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

 
FirstEnergy has equity ownership interests in certain businesses that are accounted for using the equity method of accounting. 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. Certain derivatives 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 and are therefore excluded from the tables below. Contracts that are not exempt from such treatment include certain power purchase agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policies Act of 1978. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs or regulatory liability for below-market costs. The change in the fair value of commodity derivative contracts related to energy production during the three months and nine months ended September 30, 2009 are summarized in the following table:

 
100

 


 
Three Months Ended
 
Nine Months Ended
 
 
September 30, 2009
 
September 30, 2009
 
Fair Value of Commodity Derivative Contracts
 
Non-Hedge
 
Hedge
 
Total
 
Non-Hedge
 
Hedge
 
Total
 
 
(In millions)
 
Change in the Fair Value of
                       
Commodity Derivative Contracts:
                       
Outstanding net liability at beginning of period
$
(515
)
$
(14
)
$
(529
)
$
(304
)
$
(41
)
$
(345
)
Additions/change in value of existing contracts
 
(23
)
 
13
   
(10
)
 
(404
)
 
10
   
(394
)
Settled contracts
 
92
   
(5
)
 
87
   
262
   
25
   
287
 
Outstanding net liability at end of period (1)
$
(446
)
$
(6
)
$
(452
)
$
(446
)
$
(6
)
$
(452
)
                                     
Non-commodity Net Liabilities at End of Period:
                                   
Interest rate swaps (2)
 
-
   
(2
)
 
(2
)
 
-
   
(2
)
 
(2
)
Net Liabilities - Derivative Contracts
at End of Period
$
(446
)
$
(8
)
$
(454
)
$
(446
)
$
(8
)
$
(454
)
                                     
Impact of Changes in Commodity Derivative
Contracts(3)
                                   
Income statement effects (pre-tax)
$
(2
)
$
-
 
$
(2
)
$
2
 
$
-
 
$
2
 
Balance sheet effects:
                                   
Other comprehensive income (pre-tax)
$
-
 
$
8
 
$
8
 
$
-
 
$
35
 
$
35
 
Regulatory assets (net)
$
(71
)
$
-
 
$
(71
)
$
144
 
$
-
 
$
144
 

 
(1)
Includes $446 million in non-hedge commodity derivative contracts (primarily with NUGs) which are offset by a regulatory asset.
 
(2)
Interest rate swaps are treated as cash flow or fair value hedges.
 
(3)
Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions.

  Derivatives are included on the Consolidated Balance Sheet as of September 30, 2009 as follows:

Balance Sheet Classification
 
Non-Hedge
 
Hedge
 
Total
 
   
(In millions)
 
Current-
             
Other assets
 
$
-
 
$
13
 
$
13
 
Other liabilities
   
-
   
(18)
   
(18)
 
                     
Non-Current-
                   
Other deferred charges
   
239
   
-
   
239
 
Other non-current liabilities
   
(685)
   
(3)
   
(688)
 
Net liabilities
 
$
(446)
 
$
(8)
 
$
(454)
 

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

Source of Information
                             
- Fair Value by Contract Year
 
2009(1)
 
2010
 
2011
 
2012
 
2013
 
Thereafter
 
Total
 
   
(In millions)
 
Prices actively quoted(2)
 
$
(2)
 
$
(13
)
$
-
 
$
-
 
$
-
 
$
-
 
$
(15
)
Other external sources(3)
   
(64)
   
(251
)
 
(209
)
 
(129
)
 
-
   
-
   
(653
)
Prices based on models
   
-
   
-
   
-
   
-
   
(1
)
 
217
   
216
 
Total
 
$
(66)
 
$
(264
)
$
(209
)
$
(129
)
$
(1
)
$
217
 
$
(452
)

(1)                For the fourth quarter of 2009.
(2)                Represents exchange traded NYMEX futures and options.
(3)                Primarily represents contracts based on broker and ICE quotes.

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 September 30, 2009. Based on derivative contracts held as of September 30, 2009, an adverse 10% change in commodity prices would decrease net income by approximately $4 million during the next 12 months.

 
101

 


Forward Starting Swap Agreements - Cash Flow Hedges

FirstEnergy uses forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. For the three months and nine months ended September 30, 2009, FirstEnergy terminated forward swaps with a notional value of $2.3 billion and $2.4 billion, respectively. FirstEnergy recognized losses of approximately $17 million and $18 million, respectively -- of which the ineffective portion recognized as an adjustment to interest expense was immaterial. The remaining effective portions will be amortized to interest expense over the life of the hedged debt.

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

Equity Price Risk

FirstEnergy provides a noncontributory qualified defined benefit pension plan that covers substantially all of its employees and non-qualified pension plans that cover certain employees. The plan provides defined benefits based on years of service and compensation levels. FirstEnergy also provides health care benefits (which include certain employee contributions, deductibles, and co-payments) upon retirement to employees hired prior to January 1, 2005, their dependents, and under certain circumstances, their survivors. The benefit plan assets and obligations are remeasured annually using a December 31 measurement date. FirstEnergy’s other postretirement benefits plans were remeasured as of May 31, 2009 as a result of a plan amendment announced on June 2, 2009, which reduces future health care coverage subsidies paid by FirstEnergy on behalf of plan participants. The remeasurement and plan amendment will result in a $48 million reduction in FirstEnergy’s net postretirement benefit cost (including amounts capitalized) for the remainder of 2009, including a $27 million reduction that is applicable to the first nine months of 2009 (see Note 6). In the third quarter of 2009, the Plan also incurred a $13 million net postretirement benefit cost (including amounts capitalized) related to an additional liability created by the VERO offered by FirstEnergy to qualified employees (see Note 6). On September 2, 2009, FirstEnergy elected to remeasure its qualified defined pension plan due to a $500 million voluntary contribution made by the Utilities and ATSI. The remeasurement and voluntary contribution decreased FirstEnergy’s accumulated other comprehensive income by approximately $494 million ($304 million, net of tax) in the third quarter of 2009 and will reduce FirstEnergy’s net postretirement benefit cost (including amounts capitalized) for the remainder of 2009 by $7 million ($2 million is applicable to the third quarter of 2009) (see Note 6). Reductions in plan assets from investment losses during 2008 resulted in a decrease to the plans' funded status of $1.7 billion and an after-tax decrease to common stockholders' equity of $1.2 billion. For the first eight months of 2009, the actual plan asset investment results were 9.4% compared to (23.8%) for 2008. As of December 31, 2008, the pension plan was underfunded and it remained underfunded after the voluntary contribution and remeasurement on August 31, 2009. FirstEnergy currently estimates that additional cash contributions will be required in 2014 for the 2013 plan year.

Nuclear decommissioning trust funds have been established to satisfy NGC's and the Utilities' nuclear decommissioning obligations. As of September 30, 2009, approximately 15% of the funds were invested in equity securities and 85% were invested in fixed income securities, with limitations related to concentration and investment grade ratings. The equity securities are carried at their market value of approximately $278 million as of September 30, 2009. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $28 million reduction in fair value as of September 30, 2009. The decommissioning trusts of JCP&L and the Pennsylvania Companies are subject to regulatory accounting, with unrealized gains and losses recorded as regulatory assets or liabilities, since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers. NGC, OE and TE recognize in earnings the unrealized losses on available-for-sale securities held in their nuclear decommissioning trusts based on the guidance for other-than-temporary impairments. On June 18, 2009, the NRC informed FENOC that its review tentatively concluded that a shortfall ($147.5 million net present value) existed in the value of the decommissioning trust fund for Beaver Valley Unit 1. On November 5, 2009, the NRC issued a renewed operating license for Beaver Valley Power Station, Units 1 and 2. The operating licenses for these facilities were extended until 2036 and 2047 for Units 1 and 2, respectively. Renewal of the operating license for Beaver Valley Unit 1 (see Nuclear Plant Matters) is expected to mitigate the estimated shortfall in the unit’s nuclear decommissioning funding status. FENOC will continue to work with the NRC Staff as it completes its review of the license renewal application, and expects to obtain renewed licenses for the Beaver Valley Power Station in 2009. FENOC continues to communicate with the NRC regarding future actions to provide reasonable assurance for decommissioning funding. Such actions may include additional parental guarantees or contributions to those funds.

 
102

 


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. We engage 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.

We maintain credit policies with respect to our 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 our credit program, we aggressively manage the quality of our portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As of September 30, 2009, the largest credit concentration was with JP Morgan, which is currently rated investment grade, representing 10.7% of our total approved credit risk.

OUTLOOK

 State Regulatory Matters

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

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

The Utilities and ATSI recognize, as regulatory assets, costs which the FERC, the PUCO, the PPUC and the NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $172 million as of September 30, 2009 (JCP&L - $42 million, Met-Ed - $102 million and Penelec - $28 million). Regulatory assets not earning a current return (primarily for certain regulatory transition costs and employee postretirement benefits) are expected to be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec. The following table discloses net regulatory assets by company:

   
September 30,
 
December 31,
 
Increase
 
Regulatory Assets
 
2009
 
2008
 
(Decrease)
 
   
(In millions)
 
OE
 
$
494
 
$
575
 
$
(81
)
CEI
   
592
   
784
   
(192
)
TE
   
77
   
109
   
(32
)
JCP&L
   
950
   
1,228
   
(278
)
Met-Ed
   
404
   
413
   
(9
)
Penelec*
   
3
   
-
   
3
 
ATSI
   
23
   
31
   
(8
)
Total
 
$
2,543
 
$
3,140
 
$
(597
)

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


 
103

 


Regulatory assets by source are as follows:

   
September 30,
 
December 31,
 
Increase
 
Regulatory Assets By Source
 
2009
 
2008
 
(Decrease)
 
   
(In millions)
 
Regulatory transition costs
 
 $
1,142
 
$
1,452
 
$
(310
)
Customer shopping incentives
   
192
   
420
   
(228
)
Customer receivables for future income taxes
   
339
   
245
   
94
 
Loss on reacquired debt
   
51
   
51
   
-
 
Employee postretirement benefits
   
25
   
31
   
(6
)
Nuclear decommissioning, decontamination
                   
and spent fuel disposal costs
   
(152
)
 
(57
)
 
(95
)
Asset removal costs
   
(228
)
 
(215
)
 
(13
)
MISO/PJM transmission costs
   
207
   
389
   
(182
)
Purchased power costs
   
356
   
214
   
142
 
Distribution costs
   
525
   
475
   
50
 
Other
   
86
   
135
   
(49
)
Total
 
$
2,543
 
$
3,140
 
$
(597
)

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

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

In April 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the MISO region and found it to be in full compliance with all audited reliability standards. Similarly, in October 2008, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the PJM region and found it to be in full compliance with all audited reliability standards.

On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations, with customers in the affected area losing power. Power was restored to most customers within a few hours and to all customers within eleven hours. On December 16, 2008, JCP&L provided preliminary information about the event to certain regulatory agencies, including the NERC. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. The initial phase of the investigation required JCP&L to respond to the NERC’s request for factual data about the outage. JCP&L submitted its written response on May 1, 2009. The NERC conducted on site interviews with personnel involved in responding to the event on June 16-17, 2009. On July 7, 2009, the NERC issued additional questions regarding the event and JCP&L replied as requested on August 6, 2009. JCP&L is not able at this time to predict what actions, if any, that the NERC may take based on the data submittals or interview results.

On June 5, 2009, FirstEnergy self-reported to ReliabilityFirst a potential violation of NERC Standard PRC-005 resulting from its inability to validate maintenance records for 20 protection system relays in JCP&L’s and Penelec’s transmission systems. These potential violations were discovered during a comprehensive field review of all FirstEnergy substations to verify equipment and maintenance database accuracy. FirstEnergy has completed all mitigation actions, including calibrations and maintenance records for the relays. ReliabilityFirst issued an Initial Notice of Alleged Violation on June 22, 2009. The NERC approved FirstEnergy’s mitigation plan on August 19, 2009, and submitted it to the FERC for approval on August 19, 2009. FirstEnergy is not able at this time to predict what actions or penalties, if any, that ReliabilityFirst will propose for this self-report of violation.


 
104

 


Ohio

On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing to support a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of its investigation into the distribution rate request. On January 21, 2009, the PUCO granted the Ohio Companies’ application to increase electric distribution rates by $136.6 million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million). These increases went into effect for OE and TE on January 23, 2009, and for CEI on May 1, 2009. Applications for rehearing of this order were filed by the Ohio Companies and one other party on February 20, 2009. The PUCO granted these applications for rehearing on March 18, 2009 for the purpose of further consideration. The PUCO has not yet issued a substantive Entry on Rehearing.

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

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

On July 27, 2009, the Ohio Companies filed applications with the PUCO to recover three different categories of deferred distribution costs on an accelerated basis. In the Ohio Companies' Amended ESP, the PUCO approved the recovery of these deferrals, with collection originally set to begin in January 2011 and to continue over a 5 or 25 year period. The principal amount plus carrying charges through August 31, 2009 for these deferrals was a total of $305.1 million. The applications were approved by the PUCO on August 19, 2009. Recovery of this amount, together with carrying charges calculated as approved in the Amended ESP, commenced on September 1, 2009, and will be collected in the 18 non-summer months from September 2009 through May 2011, subject to reconciliation until fully collected, with $165 million of the above amount being recovered from residential customers, and $140.1 million being recovered from non-residential customers.

 
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The CBP auction occurred on May 13-14, 2009, and resulted in a weighted average wholesale price for generation and transmission of 6.15 cents per KWH. The bid was for a single, two-year product for the service period from June 1, 2009 through May 31, 2011. FES participated in the auction, winning 51% of the tranches (one tranche equals one percent of the load supply). Subsequent to the signing of the wholesale contracts, three winning bidders reached separate agreements with FES to assign a total of 21 tranches to FES for various periods. The results of the CBP were accepted by the PUCO on May 14, 2009. In addition, FES has separately contracted with numerous communities to provide retail generation service through governmental aggregation programs.

SB221 also requires electric distribution utilities to implement energy efficiency programs. Under the provisions of SB221, the Ohio Companies are required to achieve a total annual energy savings equivalent of approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013, with additional savings required through 2025. Utilities are also required to reduce peak demand in 2009 by 1%, with an additional seventy-five hundredths of one percent reduction each year thereafter through 2018. The PUCO may amend these benchmarks in certain, limited circumstances. Additionally, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they serve in 2009. The Ohio Companies are presently involved in collaborative efforts related to energy efficiency, including filing applications for approval with the PUCO, as well as other implementation efforts arising out of the Supplemental Stipulation. We expect that all costs associated with compliance will be recoverable from customers.

On June 17, 2009, the PUCO modified rules that implement the alternative energy portfolio standards created by SB221, including the incorporation of energy efficiency requirements, long-term forecast and greenhouse gas reporting and CO2 control planning. The PUCO filed the rules with the Joint Committee on Agency Rule Review (JCARR) on July 7, 2009, after which began a 65-day review period. On August 6, 2009, the PUCO withdrew alternative energy and energy efficiency/peak demand reduction rules from JCARR. On August 24, 2009, the integrated resource planning rules were also withdrawn from JCARR. The Ohio Companies and one other party filed applications for rehearing on the rules with the PUCO on July 17, 2009. On August 11, 2009, the PUCO issued an entry on rehearing granting the applications for rehearing only for purposes of further consideration of the issues raised.

On October 15, 2009, the PUCO issued a second Entry on Rehearing, modifying certain of its previous rules. Modified rules previously withdrawn from JCARR were refiled with JCARR on October 16 and October 19, 2009. The rules set out the manner in which the electric utilities, including the Ohio companies, will be required to comply with benchmarks contained in SB 221 related to the employment of alternative energy resources, energy efficiency/peak demand reduction programs as well as greenhouse gas reporting requirements and changes to long term forecast reporting requirements. The rules severely restrict the types of renewable energy resources and energy efficiency and peak reduction programs that may be included toward meeting the statutory goals, which is expected to significantly increase the cost of compliance for the Ohio Companies' customers. On October 23, 2009, the rules were placed in a “to be re-filed” status by JCARR. It is currently unclear what form the final rules may take or their potential impact on the Ohio Companies. As a result of this uncertainty surrounding the rules, as well as the Commission’s failure to address certain energy efficiency applications submitted by the Ohio Companies throughout the year and the Commission’s recent directive to postpone the launch of a Commission-approved energy efficiency program, the Ohio Companies, on October 27, 2009, submitted an application to amend their 2009 statutory energy efficiency benchmarks to zero. Absent this regulatory relief the Ohio Companies may not be able to meet their 2009 statutory energy efficiency benchmarks, which may result in the assessment of a forfeiture by the PUCO. The Ohio Companies asked the Commission to issue a ruling on or before December 2, 2009.

In August and October 2009, the Ohio Companies conducted RFPs to secure Renewable Energy Credits (RECs). The RFPs includes solar and other renewable energy RECs, including those generated in Ohio. The RECs from these two RFPs will be used to help meet the renewable energy requirements established under Senate Bill 221 for 2009, 2010, and 2011.

On October 20, 2009, the Ohio Companies filed an MRO to procure electric generation service for the period beginning June 1, 2011. The proposed MRO would establish a CBP to secure generation supply for customers who do not shop with an alternative supplier and would be similar, in all material respects, to the CBP conducted in May 2009 in that it would procure energy, capacity and certain transmission services on a slice of system basis. However, unlike the May 2009 CBP, the MRO would include multiple bidding sessions and multiple products with different delivery periods for generation supply designed to reduce potential volatility, reduce supplier risk and encourage bidder participation. A technical conference was held on October 29, 2009, at the PUCO. Pursuant to SB221, the PUCO has 90 days to determine whether the MRO meets certain statutory requirements, therefore, the Ohio Companies have requested a PUCO determination by January 18, 2010. Under a determination that such statutory requirements were met, the Ohio Companies would be able to implement the MRO and conduct the CBP

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.

 
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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. The TSCs included a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010. Various interveners filed complaints against those filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing Met-Ed to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted. Hearings and briefing for both Met-Ed and Penelec have concluded. On August 11, 2009, the ALJ issued a Recommended Decision to the PPUC approving Met-Ed’s and Penelec’s TSCs as filed and dismissing all complaints. Exceptions by various interveners were filed and reply exceptions were filed by Met-Ed and Penelec. The Companies are now awaiting a PPUC decision.

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

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

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

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

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

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

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

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

Act 129 requires utilities to file with the PPUC an energy efficiency and peak load reduction plan by July 1, 2009. On January 15, 2009, in compliance with Act 129, the PPUC issued its proposed guidelines for the filing of utilities’ energy efficiency and peak load reduction plans. On July 1, 2009, Met-Ed, Penelec, and Penn filed EE&C Plans with the PPUC in accordance with Act 129. The Pennsylvania Companies submitted a supplemental filing on July 31, 2009, to revise the Total Resource Cost test items in the EE&C Plans pursuant to the PPUC’s June 23, 2009 Order. Following an evidentiary hearing and briefing, the Companies filed revised EE&C Plans on September 21, 2009. In an Order entered October 28, 2009, the PPUC approved in part, and rejected in part, the Pennsylvania Companies’ filing. The Companies must file revised – EE&C plans by December 28, 2009, incorporating minor revisions required by the PPUC. These revisions are not expected to impose any additional financial obligations on the Pennsylvania Companies.


 
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Act 129 also requires utilities to file with the PPUC a smart meter technology procurement and installation plan by August 14, 2009. On June 18, 2009, the PPUC issued its guidelines related to Smart Meter deployment. On August 14, 2009, Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation Plan as required by Act 129. A litigation schedule has been adopted which includes a Technical Conference and evidentiary hearings this fall. The Pennsylvania Companies expect the PPUC to act on the plans early next year.
 
Legislation addressing rate mitigation and the expiration of rate caps was not enacted in 2008; however, several bills addressing these issues have been introduced in the current legislative session, which began in January 2009. The final form and impact of such legislation is uncertain.

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

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

On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance filing to the PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the residential class with a corresponding increase in the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $59 million), overall rates would remain unchanged. On July 30, 2009, the PPUC entered an order approving the 5-year NUG Statement, approving the reduction of the CTC, and directing Met-Ed and Penelec to file a tariff supplement implementing this change. On July 31, 2009, Met-Ed and Penelec filed tariff supplements decreasing the CTC rate in compliance with the July 30, 2009 order, and increasing the generation rate in compliance with the companies’ Restructuring Orders of 1998. On August 14, 2009, the PPUC issued Secretarial Letters approving Met-Ed and Penelec’s compliance filings. By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30 day comment period on whether “the Restructuring Settlement allows NUG over collection for select and isolated months to be used to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists.”   In response to the Tentative Order comments were filed by the Office of Small Business Advocate, Office of Consumer Advocate, York County Solid Waste and Refuse Authority, ARIPPA, the Met-Ed Industrial Users Group and Penelec Industrial Customer Alliance objecting to the above accounting method utilized by Met-Ed and Penelec. The Companies filed reply comments on October 26, 2009, and await the decision of the PPUC.

New Jersey 

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of September 30, 2009, the accumulated deferred cost balance totaled approximately $102 million.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004, supporting continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DPA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set. On March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009. This matter is currently pending before the NJBPU.

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

 
 
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The EMP was issued on October 22, 2008, establishing five major goals:

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

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

·  
meet 30% of the state’s electricity needs with renewable energy by 2020;
 
·  
examine smart grid technology and develop additional cogeneration and other generation resources consistent with the state’s greenhouse gas targets; and

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

On January 28, 2009, the NJBPU adopted an order establishing the general process and contents of specific EMP plans that must be filed by New Jersey electric and gas utilities in order to achieve the goals of the EMP. Such utility specific plans are due to be filed with the BPU by July 1, 2010. At this time, FirstEnergy cannot determine the impact, if any, the EMP may have on their operations.

In support of the New Jersey Governor's Economic Assistance and Recovery Plan, JCP&L announced a proposal to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. Under the proposal, an estimated $40 million would be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations. In addition, approximately $34 million would be spent implementing new demand response programs as well as expanding on existing programs. Another $11 million would be spent on energy efficiency, specifically replacing transformers and capacitor control systems and installing new LED street lights. The remaining $13 million would be spent on energy efficiency programs that would complement those currently being offered. The project relating to expansion of the existing demand response programs was approved by the BPU on August 19, 2009, and implementation will begin in 2009. Implementation of the remaining projects is dependent upon resolution of regulatory issues including recovery of the costs associated with the proposal.

 FERC Matters

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or SECA) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order is pending before the FERC, and in the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements.

PJM Transmission Rate

On January 31, 2005, certain PJM transmission owners made filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design, notably AEP, which proposed to create a "postage stamp," or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. AEP's proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order ("Opinion 494") finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.

 
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On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. On February 11, 2008, AEP appealed the FERC’s April 19, 2007, and January 31, 2008, orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit. Oral arguments were held on April 13, 2009. The Seventh Circuit Court of Appeals issued a decision on August 6, 2009, that remanded the rate design to FERC and denied AEP’s appeal. A request for rehearing and rehearing en banc by Baltimore Gas & Electric and Old Dominion electric Cooperative was denied by the Seventh Circuit on October 20, 2009.

The FERC’s orders on PJM rate design prevented 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 reduces the cost of future transmission to be recovered from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding Judge to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement subject to the submission of a compliance filing. The compliance filing was submitted on August 29, 2008, and the FERC issued an order accepting the compliance filing on October 15, 2008. On November 14, 2008, PJM submitted revisions to its tariff to incorporate cost responsibility assignments for below 500 kV upgrades included in PJM’s Regional Transmission Expansion Planning process in accordance with the settlement. The FERC conditionally accepted the compliance filing on January 28, 2009. PJM submitted a further compliance filing on March 2, 2009, which was accepted by the FERC on April 10, 2009. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. An initial decision was issued by the Presiding Judge on September 18, 2008. PJM and FERC trial staff each filed a Brief on Exceptions to the initial decision on October 20, 2008. Briefs Opposing Exceptions were filed on November 10, 2008.

Post Transition Period Rate Design

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

On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have the FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “Super Region” that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers. Lower voltage facilities would continue to be recovered in the local utility transmission rate zone through a license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On January 31, 2008, the FERC issued an order denying the complaint. The effect of this order is to prevent the shift of significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP was denied by the FERC on December 19, 2008. On February 17, 2009, AEP appealed the FERC’s January 31, 2008, and December 19, 2008, orders to the U.S. Court of Appeals for the Seventh Circuit. FESC, on behalf of its affiliated operating utility companies, filed a motion to intervene on March 10, 2009. The Seventh Circuit Court of Appeals has held this appeal in abeyance pending resolution of the Order 494 appeal discussed above.

RTO Consolidation

On August 17, 2009, FirstEnergy filed an application with the FERC requesting to consolidate its transmission assets and operations into PJM. Currently, FirstEnergy’s transmission assets and operations are divided between PJM and MISO. The consolidation would make the transmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. Most of FirstEnergy’s transmission assets in Pennsylvania and all of the transmission assets in New Jersey already operate as a part of PJM.

To ensure a definitive ruling at the same time FERC rules on its request to integrate ATSI into PJM, on October 19, 2009, FirstEnergy filed a related complaint with FERC on the issue of allocating transmission costs to the ATSI footprint for high voltage transmission projects approved prior to FirstEnergy’s integration into PJM.

 
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FirstEnergy has requested that FERC rule on its application by December 17, 2009, to provide time to permit management to make a decision on whether to integrate ATSI into PJM prior to the 2010 Base Residual Auction for capacity. Subject to a satisfactory FERC ruling, the integration is expected to be complete on June 1, 2011, to coincide with delivery of power under the next competitive generation procurement process for FirstEnergy's Ohio companies.

On September 4, 2009, the PUCO opened a case to take comments from Ohio stakeholders regarding the RTO consolidation. FirstEnergy filed extensive comments in the PUCO case on September 25, 2009 and reply comments on October 13, 2009 and attended a public hearing on September 15, 2009 to respond to questions regarding the RTO consolidation.

Several parties have intervened in the regulatory dockets at the FERC and at the PUCO. Certain interveners have commented and protested particular elements of the proposed RTO consolidation, including an exit fee to MISO, integration costs to PJM, and cost-allocations of future transmission upgrades in PJM and MISO. The result of these comments and protests could delay or otherwise have a material financial effect on the proposed RTO consolidation.

Changes ordered for PJM Reliability Pricing Model (RPM) Auction

On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act. On September 19, 2008, the FERC denied the RPM Buyers’ complaint. The FERC also ordered PJM to file on or before December 15, 2008, a report on potential adjustments to the RPM program as suggested in a Brattle Group report. On December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the RPM program. PJM also requested that the FERC conduct a settlement hearing to address changes to the RPM and suggested that the FERC should rule on the tariff amendments only if settlement could not be reached in January, 2009. The request for settlement hearings was granted. Settlement had not been reached by January 9, 2009 and, accordingly, FirstEnergy and other parties submitted comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief Judge issued an order terminating settlement discussions. On February 9, 2009, PJM and a group of stakeholders submitted an offer of settlement, which used the PJM December 12, 2008 filing as its starting point, and stated that unless otherwise specified, provisions filed by PJM on December 12, 2008, apply.

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

PJM has reconvened the Capacity Market Evolution Committee (CMEC) and has scheduled a CMEC Long-Term Issues Symposium to address near-term changes directed by the March 26, 2009 Order and other long-term issues not addressed in the February 2009 settlement. PJM made a compliance filing on September 1, 2009, incorporating tariff changes directed by the March 26, 2009 Order. The tariff changes, which provide for incremental improvements to the RPM, will be effective November 1, 2009, pending FERC approval. In addition, the CMEC continues to work to address additional compliance items directed by the March 26, 2009 Order. Another compliance filing is due December 1, 2009.

MISO Resource Adequacy Proposal

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

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

FES Sales to Affiliates

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

On May 13-14, 2009, the Ohio Companies held an auction to secure generation supply for their PLR obligation. The results of the auction were accepted by the PUCO on May 14, 2009. Twelve bidders qualified to participate in the auction with nine successful bidders each securing a portion of the Ohio Companies' total supply needs. FES was the successful bidder for 51 tranches, and subsequently purchased 21 additional tranches from other bidders. The auction resulted in an overall weighted average wholesale price of 6.15 cents per KWH for generation and transmission. The new prices for PLR service went into effect with usage beginning June 1, 2009, and continuing through May 31, 2011.

On November 3, 2009, FES, Met-Ed, Penelec and Waverly restated their partial requirements power purchase agreement for 2010. The Fourth Restated Partial Requirements Agreement continues to limit the amount of capacity resources required to be supplied by FES to 3544 MW, but requires FES to supply essentially all of Met-Ed, Penelec, and Waverly’s energy requirements in 2010 Under the new agreement, Met-Ed, Penelec, and Waverly assign 1300 MW of existing energy purchases to FES to assist it in supplying Buyers’ power supply requirements and managing congestion expenses. FES can either sell the assigned power from the third party into the market or use it to serve the Met-Ed/Penelec load. FES is responsible for obtaining additional power supplies in the event of failure of supply of the assigned energy purchase contracts. Prices for the power sold by FES were increased to $42.77 and $44.42, respectively for Met-Ed and Penelec. In addition, FES agreed to reimburse Met-Ed and Penelec, respectively, for congestion expenses and marginal losses in excess of $208 million and $79 million as billed by PJM in 2010, and associated with delivery of power by FES under the Fourth Restated Partial Requirements Agreement. The Fourth Restated Partial Requirements Agreement terminates at the end of 2010.

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 $800 million for the period 2009-2013.

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

Clean Air Act Compliance

FirstEnergy is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in the shutdown of the generating unit involved and/or civil or criminal penalties of up to $37,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. FirstEnergy believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

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

In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices or repowering and provides for stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree, including repowering Burger Units 4 and 5 for biomass fuel consumption, are currently estimated to be $706 million for 2009-2012 (with $414 million expected to be spent in 2009).

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. In July 2008, three additional complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the three complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. On October 14, 2008, the Court granted FGCO’s motion to consolidate discovery for all four complaints pending against the Bruce Mansfield Plant. On August 17, 2009, a settlement of the PennFuture complaint was reached with PennFuture and one of the three individual complaintants. On October 16, 2009, the Court approved the settlement and dismissed the claims of PennFuture and of the settling individual complaintant. The other two non-settling complaintants are now represented by counsel handling the three cases filed in July 2008. FGCO believes those claims are without merit and intends to defend itself against the allegations made in those three complaints. The Pennsylvania Department of Health, under a Cooperative Agreement with the Agency for Toxic Substances and Disease Registry, completed a Health Consultation regarding the Mansfield Plant and issued a report dated March 31, 2009 which concluded there is insufficient sampling data to determine if any public health threat exists for area residents due to emissions from the Mansfield Plant. The report recommended additional air monitoring and sample analysis in the vicinity of the Mansfield Plant, which the Pennsylvania Department of Environmental Protection has completed.

On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. Specifically, Connecticut and New Jersey allege that "modifications" at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. On December 5, 2008, New Jersey filed an amended complaint, adding claims with respect to alleged modifications that occurred after GPU’s sale of the plant. Met-Ed filed a Motion to Dismiss the claims in New Jersey’s Amended Complaint and Connecticut’s Complaint on February 19, 2009, and on September 30, 2009, respectively. The Court granted Met-Ed's motion to dismiss New Jersey’s and Connecticut’s claims for injunctive relief against Met-Ed, but denied Met-Ed’s motion to dismiss the claims for civil penalties on statute of limitations grounds in order to allow the states to prove either that the application of the discovery rule or the doctrine of equitable tolling bars application of the statute of limitations.


 
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On January 14, 2009, the EPA issued a NOV to Reliant alleging new source review violations at the Portland Generation Station based on “modifications” dating back to 1986. Met-Ed is unable to predict the outcome of this matter. The EPA’s January 14, 2009, NOV also alleged new source review violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of the Keystone Station and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter.
 
On June 11, 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. alleging that "modifications" at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program. Mission Energy is seeking indemnification from Penelec, the co-owner (along with New York State Electric and Gas Company) and operator of the Homer City Power Station prior to its sale in 1999. The scope of Penelec’s indemnity obligation to and from Mission Energy is disputed. Penelec is unable to predict the outcome of this matter.
 
On May 16, 2008, FGCO received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an Administrative Consent Order modifying that request and setting forth a schedule for FGCO’s response. On October 27, 2008, FGCO received a second request from the EPA for information pursuant to Section 114(a) of the CAA for additional operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants. On August 12, 2009, the EPA issued a Finding of Violation and NOV alleging violations of the Clean Air Act and Ohio regulations, including the prevention of significant deterioration (“PSD”), non-attainment new source review (NNSR”), and Title V regulations at the Eastlake, Lakeshore, Bay Shore, and Ashtabula generating plants. The EPA’s NOV alleges equipment replacements occurring during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. On September 15, 2009, FGCO received an additional information request pursuant to Section 114(a) of the Clean Air Act requiring FirstEnergy to submit certain operating and maintenance information and planning information regarding the Eastlake, Lake Shore, Bay Shore and Ashtabula generating plants. On November 3, 2009, FGCO received a letter providing notification that the EPA is evaluating whether certain scheduled maintenance at the Eastlake generating plant may constitute a major modification under the NSR provisions of the CAA. FGCO intends to comply with the CAA, including EPA’s information requests, but, at this time, is unable to predict the outcome of this matter. A June 15, 2006 finding of violation and NOV in which EPA alleged CAA violations at the Bay Shore Generating Plant remains unresolved and FGCO is unable to predict the outcome of such matter.
 
On August 18, 2008, FirstEnergy received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding its formerly-owned Avon Lake and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. FirstEnergy intends to fully comply with the EPA’s information request, but, at this time, is unable to predict the outcome of this matter.

National Ambient Air Quality Standards

In March 2005, the EPA finalized CAIR, covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia, based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR requires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOX emissions to 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. On December 23, 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s July 11, 2008 opinion. On July 10, 2009, the United States Court of Appeals for the District of Columbia ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOX SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the "8-hour" ozone NAAQS. FGCO's future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA in response to the Court’s ruling.

 
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Mercury Emissions
 
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the Court vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA petitioned for rehearing by the entire Court, which denied the petition on May 20, 2008. On October 17, 2008, the EPA (and an industry group) petitioned the United States Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the EPA moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the EPA’s petition and denied the industry group’s petition. On October 21, 2009, the EPA opened a 30-day comment period on a proposed consent decree that would obligate the EPA to propose maximum achievable control technology (MACT) regulations for mercury and other hazardous air pollutants by March 16, 2011, and to finalize the regulations by November 16, 2011.  FGCO’s future cost of compliance with MACT regulations may be substantial and will depend on the action taken by the EPA and on how any future regulations are ultimately implemented.
 
Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. On January 30, 2009, the Commonwealth Court of Pennsylvania declared Pennsylvania’s mercury rule “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule. It is anticipated that compliance with these regulations, if the Commonwealth Court’s rulings were reversed on appeal and Pennsylvania’s mercury rule was implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant (FirstEnergy’s only Pennsylvania coal-fired power plant) until 2015, if at all.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing, by 2012, the amount of man-made GHG, including CO2, emitted by developed countries. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. The EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity used in the United States comes from renewable sources by 2012, increasing to 25% by 2025, and implementing an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050.

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the House of Representatives passed one such bill, the American Clean Energy and Security Act of 2009, on June 26, 2009. The Senate continues to consider a number of measures to regulate GHG emissions. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. On April 17, 2009, the EPA released a “Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s proposed finding concludes that the atmospheric concentrations of several key greenhouse gases threaten the health and welfare of future generations and that the combined emissions of these gases by motor vehicles contribute to the atmospheric concentrations of these key greenhouse gases and hence to the threat of climate change. Although the EPA’s proposed finding, if finalized, does not establish emission requirements for motor vehicles, such requirements would be expected to occur through further rulemakings. Additionally, while the EPA’s proposed findings do not specifically address stationary sources, including electric generating plants, those findings, if finalized, would be expected to support the establishment of future emission requirements by the EPA for stationary sources, . On September 23, 2009, the EPA finalized a GHG reporting rule establishing a national GHG emissions collection and reporting program. The EPA rules will require FirstEnergy to measure GHG emissions commencing in 2010 and submit reports commencing in 2011. On September 30, 2009, EPA proposed new thresholds for GHG emissions that define when Clean Air Act permits under the New Source Review and Title V operating permits programs would be required. EPA is proposing a major source emissions applicability threshold of 25,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) for existing facilities under the Title V operating permits program and the Prevention of Significant Determination (PSD) portion of NSR. EPA is also proposing a significance level between 10,000 and 25,000 tpy CO2e to determine if existing major sources making modifications that result in an increase of emissions above the significance level would be required to obtain a PSD permit.


 
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On September 21, 2009, the U.S. Court of Appeals for the Second Circuit and on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit, reversed and remanded lower court decisions that had dismissed complaints alleging damage from GHG emissions on jurisdictional grounds.  These cases involve common law tort claims, including public and private nuisance, alleging that GHG emissions contribute to global warming and result in property damages.   Connecticut v. AEP, No. 05-5105-cv (2d Cir. 2009)(seeking injunctive relief only); Comer v. Murphy Oil USA, No. 07-6-756 (5th Cir. 2009)(seeking damages only), respectively.  While FirstEnergy is not a party to either litigation, should the courts of appeals decisions be affirmed, FirstEnergy and/or one or more of its subsidiaries could be named in actions making similar allegations.

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

Clean Water Act

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

On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 1, 2009, the Supreme Court of the United States reversed one significant aspect of the Second Circuit Court’s opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. The EPA will now take up consideration of the rule on remand and take further action consistent with the opinions of the Supreme Court and the Court of Appeals, including whether to exercise its discretion to retain or modify the cost-benefit rule as it appeared in the initial regulation. It is expected that the EPA will issue a proposed rule on remand in 2010. The Courts’ opinions have created significant uncertainty about the specific nature, scope and timing of the final compliance requirements .FirstEnergy is studying various control options and their costs and effectiveness. Depending on the results of such studies and the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

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

As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate non-hazardous waste. In February 2009, the EPA requested comments from the states on options for regulating coal combustion wastes, including regulation as non-hazardous waste or regulation as a hazardous waste. In March and June 2009, the EPA requested information from FGCO’s Bruce Mansfield Plant regarding the management of coal combustion wastes. The EPA is reviewing its previous determination that Federal regulation of coal ash as a hazardous waste is not appropriate. The EPA has indicated an intent to propose regulations regarding this issue by the end of the year. Additional regulations of fossil-fuel combustion waste products could have a significant impact on our management, beneficial use, and disposal, of coal ash. FGCO's future cost of compliance with any coal combustion waste regulations which may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the states.


 
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The Utilities have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the consolidated balance sheet as of September 30, 2009, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $104 million (JCP&L - $77 million, TE - $1 million, CEI - $1 million, FGCO - $1 million and FirstEnergy - $24 million) have been accrued through September 30, 2009. Included in the total are accrued liabilities of approximately $68 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

Other Legal Proceedings

Power Outages and Related Litigation 

In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages due to the outages.

After various motions, rulings and appeals, the Plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability, and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. The class was decertified twice by the trial court, and appealed both times by the Plaintiffs, with the results being that: (1) the Appellate Division limited the class only to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation which resulted in planned and unplanned outages in the area during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. On March 31, 2009, the trial court again granted JCP&L’s motion to decertify the class. On April 20, 2009, the Plaintiffs filed a motion for leave to take an interlocutory appeal to the trial court's decision to decertify the class, which was granted by the Appellate Division on June 15, 2009. Plaintiffs filed their appellate brief on August 25, 2009, and JCP&L filed an opposition brief on September 25, 2009. On or about October 13, 2009, Plaintiffs filed their reply brief in further support of their appeal of the trial court's decision decertifying the class. JCP&L is now waiting for the Appellate Division to schedule the appeal for oral arguments.

Nuclear Plant Matters 

In August 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. On November 5, 2009, the NRC issued a renewed operating license for Beaver Valley Power Station, Units 1 and 2. The operating licenses for these facilities was extended until 2036 and 2047 for Units 1 and 2, respectively.

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of September 30, 2009, FirstEnergy had approximately $1.9 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry, and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy provided an additional $80 million parental guarantee associated with the funding of decommissioning costs for these units and indicated that it planned to contribute an additional $80 million to these trusts by 2010. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s obligations to fund the trusts may increase. The recent disruption in the capital markets and its effects on particular businesses and the economy in general also affects the values of the nuclear decommission trusts. On June 18, 2009, the NRC informed FENOC that its review tentatively concluded that a shortfall ($147.5 million net present value) existed in the value of the decommissioning trust fund for Beaver Valley Unit 1. On July 28, 2009, FENOC submitted a letter to the NRC that stated reasonable assurance of decommissioning funding is provided for Beaver Valley Unit 1 through a combination of the existing trust fund balances, the existing $80 million parental guarantee from FirstEnergy and maintaining the plant in a safe-store configuration, or extended safe shutdown condition, after plant shutdown. On October 20, 2009, FENOC received a request for additional information (RAI) from the NRC that questions FENOC's methodology for calculating the decommissioning obligations for Beaver Valley Unit 1. Renewal of the operating license for Beaver Valley Unit 1 is expected to mitigate the estimated shortfall in the unit’s nuclear decommissioning funding status. FENOC continues to communicate with the NRC regarding future actions to provide reasonable assurance for decommissioning funding. Such actions may include additional parental guarantees or contributions to those funds.
 
 
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Other Legal Matters 

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
 
JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. A final order identifying the individual damage amounts was issued on October 31, 2007 and the award appeal process was initiated. The union filed a motion with the federal Court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. On February 25, 2009, the federal district court denied JCP&L’s motion to vacate the arbitration decision and granted the union’s motion to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009. The appeal process could take as long as 24 months. The parties are participating in the federal court's mediation programs and have held private settlement discussions. JCP&L recognized a liability for the potential $16 million award in 2005. Post-judgment interest began to accrue as of February 25, 2009, and the liability will be adjusted accordingly.

The bargaining unit employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. On July 24, 2009, FirstEnergy declared that bargaining was at an impasse and portions of its last contract offer were implemented August 1, 2009, and a voluntary retirement program was implemented on August 19, 2009.  A federal mediator is continuing to assist the parties in reaching a negotiated contract settlement. FirstEnergy has a strike mitigation plan ready in the event of a strike.

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
 
In December 2008, the FASB issued a standard on an employer’s disclosures about assets of a defined benefit pension or other postretirement plan. Requirements include disclosures about investment policies and strategies, categories of plan assets, fair value measurements of plan assets, and significant categories of risk. This standard is effective for fiscal years ending after December 15, 2009. FirstEnergy will expand its disclosures related to postretirement benefit plan assets.

In June 2009, the FASB amended the derecognition guidance in the Transfers and Servicing Topic of the FASB Accounting Standards Codification and eliminates the concept of a QSPE. It requires an evaluation of all existing QSPEs to determine whether they must be consolidated. This standard is effective for financial asset transfers that occur in fiscal years beginning after November 15, 2009. FirstEnergy does not expect this standard to have a material effect upon its financial statements.

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

In August 2009, the FASB updated the Fair Value Measurement and Disclosures Topic, which provides guidance to determine fair value when a quoted price in an active market for an identical liability is not available. In such instances, an entity should measure fair value using one of the following approaches; (i) the quoted price of an identical liability when traded as an asset; (ii) the quoted price of a similar liability or a similar liability traded as an asset; (iii) a technique based on the amount an entity would pay to transfer the identical liability; or (iv) a technique based on the amount an entity would receive to enter into an identical liability. This standard is effective for fiscal years beginning October 1, 2009. FirstEnergy does not expect this standard to have a material effect upon its financial statements.



 
118

 

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, and through its subsidiaries, FGCO and NGC, owns or leases and operates and maintains FirstEnergy's fossil and hydroelectric generation facilities and owns FirstEnergy's nuclear generation facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities.

FES' revenues have been primarily derived from the sale of electricity (provided from FES' generating facilities and through purchased power arrangements) to affiliated utility companies to meet all or a portion of their PLR and default service requirements. These affiliated power sales included a full-requirements PSA with OE, CEI and TE to supply each of their default service obligations through December 31, 2008, at prices that considered their respective PUCO-authorized billing rates. See Regulatory Matters – Ohio in our Combined Notes to the Consolidated Financial Statements for a discussion of Ohio power supply procurement issues for 2009 and beyond. On November 3, 2009, FES, Met-Ed, Penelec and Waverly restated their partial requirements power purchase agreement for 2010. The Fourth Restated Partial Requirements Agreement continues to limit the amount of capacity resources required to be supplied by FES to 3544 MW, but requires FES to supply essentially all of Met-Ed, Penelec, and Waverly’s energy requirements in 2010 Under the new agreement, Met-Ed, Penelec, and Waverly assign 1300 MW of existing energy purchases to FES to assist it in supplying Buyers’ power supply requirements and managing congestion expenses. FES can either sell the assigned power from the third party into the market or use it to serve the Met-Ed/Penelec load. FES is responsible for obtaining additional power supplies in the event of failure of supply of the assigned energy purchase contracts. Prices for the power sold by FES were increased to $42.77 and $44.42, respectively for Met-Ed and Penelec. In addition, FES agreed to reimburse Met-Ed and Penelec, respectively, for congestion expenses and marginal losses in excess of $208 million and $79 million as billed by PJM in 2010, and associated with delivery of power by FES under the Fourth Restated Partial Requirements Agreement. The Fourth Restated Partial Requirements Agreement terminates at the end of 2010. FES also supplied, through May 31, 2009, a portion of Penn's default service requirements at market-based rates as a result of Penn's 2008 competitive solicitations. FES' revenues also include competitive retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania, New Jersey, Maryland, Michigan and Illinois. These sales may provide a greater portion of revenues in future years depending upon FES' participation in its Ohio and Pennsylvania utility affiliates' power procurement arrangements.

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

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

For additional information with respect to FES, please see the information contained in FirstEnergy's Management Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances and Outlook.

Results of Operations

In the first nine months of 2009, net income increased to $668 million from $344 million in the same period in 2008. The increase in net income includes FGCO’s $252 million pre-tax gain from the sale of 9% of its participation in OVEC ($158 million after-tax), an increase in investment income of $142 million resulting primarily from the sale of securities held in the nuclear decommissioning trusts and an increase in gross sales margins.

Revenues

Revenues increased by $260 million in the first nine months of 2009 compared to the same period in 2008 primarily due to the OVEC sale and increase in revenues from non-affiliated and affiliated wholesale sales, partially offset by lower retail generation sales. The increase in revenues resulted from the following sources:

 
119

 


   
Nine Months Ended
     
   
September 30
 
Increase
 
Revenues by Type of Service
 
2009
 
2008
 
(Decrease)
 
   
(In millions)
 
Non-Affiliated Generation Sales:
             
Retail
 
$
406
 
$
485
 
$
(79
)
Wholesale
   
523
   
509
   
14
 
Total Non-Affiliated Generation Sales
   
929
   
994
   
(65
)
Affiliated Generation Sales
   
2,349
   
2,266
   
83
 
Transmission
   
57
   
113
   
(56
)
Sale of OVEC participation interest
   
252
   
-
   
252
 
Other
   
85
   
39
   
46
 
Total Revenues
 
$
3,672
 
$
3,412
 
$
260
 

The lower retail revenues resulted from the expiration of government aggregation programs in Ohio at the end of 2008 that were supplied by FES, partially offset by increased revenue in both the PJM and MISO markets. The increase in MISO retail sales is primarily the result of the acquisition of new customers and higher unit prices. The increase in PJM retail sales resulted from the acquisition of new customers, higher sales volumes and unit prices. FES has signed new government aggregation contracts with 50 communities in Ohio that will provide discounted generation prices to approximately 600,000 residential and small commercial customers. Higher non-affiliated wholesale revenues resulted from higher capacity prices in PJM offset by decreased spot market prices in PJM and increased sales volumes and favorable settlements on hedged transactions in MISO, offset by decreased sales volumes in PJM.

The increased affiliated company generation revenues were due to higher unit prices to the Ohio Companies and increased sales volumes to Met-Ed and Penelec, partially offset by lower sales volumes to the Ohio Companies. The higher unit prices reflected the results of the Ohio Companies' power procurement processes in the first half of 2009 (see Regulatory Matters – Ohio). The higher sales to the Pennsylvania Companies were due to increased Met-Ed and Penelec generation sales requirements supplied by FES, partially offset by lower sales to Penn due to decreased default service requirements in the first nine months of 2009 compared to the first nine months of 2008.

In the first quarter of 2009, FES supplied approximately 75% of the Ohio Companies’ power requirements as one of four winning bidders in the Ohio Companies' RFP process. In the second quarter of 2009, FES supplied 100% of the power for the Ohio Companies’ PLR service in April and May 2009, and approximately 56% of the Ohio Companies' supply needs beginning in June 2009. Subsequent to the Ohio Companies’ CBP, FES purchased additional tranches from other winning bidders and as of September 1, 2009, FES supplied 72% of the Ohio Companies’ PLR generation requirements.

The following tables summarize the price and volume factors contributing to changes in revenues from non-affiliated and affiliated generation sales in the first nine months of 2009 compared to the same period last year:

   
Increase
 
Source of Change in Non-Affiliated Generation Revenues
 
(Decrease)
 
   
(In millions)
 
Retail:
       
Effect of 34.3% decrease in sales volumes
 
$
(166
)
Change in prices
   
87
 
     
(79
)
Wholesale:
       
Effect of 3.5% decrease in sales volumes
   
(18
)
Change in prices
   
32
 
     
14
 
Net Decrease in Non-Affiliated Generation Revenues
 
$
(65
)

   
Increase
 
Source of Change in Affiliated Generation Revenues
 
(Decrease)
 
   
(In millions)
 
Ohio Companies:
       
Effect of 28.9% decrease in sales volumes
 
$
(508
)
Change in prices
   
557
 
     
49
 
Pennsylvania Companies:
       
Effect of 11.1% increase in sales volumes
   
57
 
Change in prices
   
(23
)
     
34
 
Net Increase in Affiliated Generation Revenues
 
$
83
 
 

 
 
120

 
 
Transmission revenues decreased $56 million due primarily to reduced loads in MISO following the expiration of the government aggregation programs in Ohio at the end of 2008. Other revenue increased $46 million primarily due to rental income associated with NGC's acquisition of additional equity interests in Perry and Beaver Valley Unit 2.

Expenses

Total expenses decreased by $82 million in the first nine months of 2009 compared with the same period of 2008. The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first nine months of 2009 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
 
 $
112
 
Change due to volume consumed
   
(230
)
     
(118
)
Nuclear Fuel:
       
Change due to increased unit costs
   
14
 
Change due to volume consumed
   
(7
)
     
7
 
Non-affiliated Purchased Power:
       
Change due to increased unit costs
   
73
 
Change due to volume purchased
   
(170
)
     
(97
)
Affiliated Purchased Power:
       
Change due to increased unit costs
   
71
 
Change due to volume purchased
   
2
 
     
73
 
Net Decrease in Fuel and Purchased Power Costs
 
$
(135
)

Fossil fuel costs decreased $118 million in the first nine months of 2009 as a result of decreased coal consumption, reflecting lower generation. Higher unit prices, which are expected to continue during the remainder of 2009, were due to increased fuel costs associated with purchases of eastern coal. Nuclear fuel costs increased slightly due to increased unit prices in the first nine months of 2009 compared to the same period of 2008.

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

Other operating expenses increased by $28 million in the first nine months of 2009 from the same period of 2008. Higher expenses in the 2009 period relate to increased transmission expenses ($64 million) due to increased net congestion charges in PJM and higher transmission loss expenses in MISO and PJM combined with increased other expenses ($14 million) relating to increased intersegment billings for leasehold costs from the Ohio Companies and higher pension expense. These increases were partially offset by lower fossil operating costs ($46 million) and nuclear operating costs ($4 million). Decreased fossil operating costs were primarily due to a reduction in contractor and material costs and more labor dedicated to capital projects compared to the prior year.

Depreciation expense increased by $22 million in the first nine months of 2009 primarily due to NGC’s increased ownership interest in Beaver Valley Unit 2 and Perry.

Other Expense

Total other expense in the first nine months of 2009 was $156 million lower than the first nine months of 2008, primarily due to a $137 million increase in earnings from nuclear decommissioning trust investments and a decline in interest expense (net of capitalized interest) of $21 million primarily due to the repayment of notes payable to affiliates.

 

 
121

 


OHIO EDISON COMPANY

  MANAGEMENT'S NARRATIVE
  ANALYSIS OF RESULTS OF OPERATIONS


OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. They provide generation services to those franchise customers electing to retain OE and Penn as their power supplier. Until December 31, 2008, OE purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that reflected the rates approved by the PUCO. See Regulatory Matters – Ohio in our Combined Notes to the Consolidated Financial Statements for a discussion of Ohio power supply procurement issues for 2009 and beyond.

For additional information with respect to OE, please see the information contained in FirstEnergy's Management Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements and Outlook.

Results of Operations

In the first nine months of 2009, net income decreased to $80 million from $166 million in the same period of 2008. The decrease primarily resulted from the completion of the recovery of transition costs at the end of 2008 and accrued obligations principally associated with the implementation of the ESP in 2009.

Revenues

Revenues increased by $59 million, or 3.0%, in the first nine months of 2009 compared with the same period in 2008, primarily due to increases in retail generation revenues ($204 million) and wholesale revenues ($80 million), partially offset by decreases in distribution throughput revenues ($203 million) and other miscellaneous revenues ($22 million).

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

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

Retail Generation KWH Sales
 
Increase
(Decrease)
 
       
Residential
 
6.6
 %
Commercial
 
10.4
 %
Industrial
 
(19.0
)%
Net Decrease in Generation Sales
 
(0.6
)%

Retail Generation Revenues
 
Increase
 
   
(In millions)
 
Residential
 
$
93
 
Commercial
   
87
 
Industrial
   
24
 
Increase in Generation Revenues
 
$
204
 

The increase in wholesale revenues was primarily due to higher average unit prices.

Revenues from distribution throughput decreased by $203 million in the first nine months of 2009 compared to the same period in 2008 due to lower average unit prices and lower KWH deliveries to all customer classes. Reduced deliveries to commercial and industrial customers reflect the weakened economy. Transition charges that ceased effective January 1, 2009, with the full recovery of related costs, were partially offset by a July 2008 increase to a PUCO-approved transmission rider and a January 2009 distribution rate increase (see Regulatory Matters – Ohio).

 
122

 

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

Distribution KWH Deliveries
 
Decrease
 
         
Residential
   
(3.3
)%
Commercial
   
(4.8
)%
Industrial
   
(24.5
)%
Decrease in Distribution Deliveries
   
(11.1
)%

Distribution Revenues
 
Decrease
 
   
(In millions)
Residential
 
$
(41
)
Commercial
   
(75
)
Industrial
   
(87
)
Decrease in Distribution Revenues
 
$
(203
)

Expenses

Total expenses increased by $171 million in the first nine months of 2009 from the same period of 2008. The following table presents changes from the prior year by expense category.

Expenses – Changes
 
Increase (Decrease)
 
     
(In millions)
 
Purchased power costs
 
$
248
 
Other operating costs
   
(51
)
Provision for depreciation
   
8
 
Amortization of regulatory assets, net
   
(28
)
General taxes
   
(6
)
Net Increase in Expenses
 
$
171
 

Higher purchased power costs reflect the results of OE’s power procurement process for retail customers in the first nine months of 2009 (see Regulatory Matters – Ohio). The decrease in other operating costs for the first nine months of 2009 was primarily due to lower transmission expenses (included in the cost of purchased power beginning June 1, 2009), partially offset by costs for economic development programs and energy efficiency obligations under OE’s ESP. Higher depreciation expense in the first nine months of 2009 reflected capital additions subsequent to the third quarter of 2008. Lower amortization of net regulatory assets was primarily due to the conclusion of transition cost amortization and distribution reliability deferrals in 2008, partially offset by lower MISO transmission cost deferrals. The decrease in general taxes for the first nine months of 2009 was primarily due to lower Ohio KWH taxes.

Other Expenses

Other expenses increased by $15 million in the first nine months of 2009 compared to the same period in 2008 primarily due to higher interest expense associated with the issuance of $300 million of FMBs by OE in October 2008.


 
123

 



THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

  MANAGEMENT'S NARRATIVE
  ANALYSIS OF RESULTS OF OPERATIONS


CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in northeastern Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain CEI as their power supplier. Until December 31, 2008, CEI purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that was reflected in rates approved by the PUCO. See Regulatory Matters – Ohio in our Combined Notes to the Consolidated Financial Statements for a discussion of Ohio power supply procurement issues for 2009 and beyond.

For additional information with respect to CEI, please see the information contained in FirstEnergy's Management Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements and Outlook.

Results of Operations

CEI experienced a net loss of $32 million in the first nine months of 2009 compared to net income of $219 million in the same period of 2008. The net loss in 2009 resulted from regulatory charges ($228 million) related to the implementation of CEI's ESP. The 2009 results were also adversely impacted by increased purchased power costs, partially offset by higher deferrals of new regulatory assets and lower other operating costs.

Revenues

Revenues decreased by $35 million, or 2.5%, in the first nine months of 2009 compared to the same period of 2008 primarily due to decreases in distribution revenues ($117 million), transmission revenues ($14 million) and other miscellaneous revenues ($7 million), partially offset by an increase in retail generation revenues ($103 million).

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

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

   
Increase
 
Retail Generation KWH Sales
 
(Decrease)
 
         
Residential
   
(2.7
)%
Commercial
   
4.8
 %
Industrial
   
(14.6
)%
Decrease in Retail Generation Sales
   
(6.4
)%

Retail Generation Revenues
 
Increase
 
   
(in millions)
 
Residential
 
$
30
 
Commercial
   
40
 
Industrial
   
33
 
Increase in Generation Revenues
 
$
103
 


 
124

 


Revenues from distribution throughput decreased by $117 million in the first nine months of 2009 compared to the same period of 2008 due to a decrease in KWH deliveries in all customer classes and lower average unit prices in the residential and commercial sectors. The lower average unit price was the net result of reduced transition rates (see Regulatory Matters – Ohio), partially offset by a PUCO-approved distribution rate increase effective May 1, 2009. The lower KWH deliveries in the first nine months of 2009 were due to weaker economic conditions and a decrease of 14% in cooling degree days in the first nine months of 2009 as compared to the previous year.

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

Distribution KWH Deliveries
 
Decrease
 
         
Residential
   
(4.0
)%
Commercial
   
(4.7
)%
Industrial
   
(18.6
)%
Decrease in Distribution Deliveries
   
(10.8
)%

       
Distribution Revenues
 
Decrease
 
   
(In millions)
 
Residential
 
$
(52
)
Commercial
   
(26
)
Industrial
   
(39
)
Decrease in Distribution Revenues
 
$
(117
)

Expenses

Total operating expenses increased by $343 million in the first nine months of 2009 compared to the same period of 2008. The following table presents the change from the prior year by expense category:

Expenses  - Changes
 
Increase
(Decrease)
 
   
(in millions)
 
Purchased power costs
 
$
254
 
Other operating costs
   
(52
)
Amortization of regulatory assets
   
200
 
Deferral of new regulatory assets
   
(63
)
General Taxes
   
4
 
Net Increase in Expenses
 
$
343
 

Higher purchased power costs reflect the results of CEI’s power procurement process for retail customers in the first nine months of 2009 (see Regulatory Matters – Ohio). Increased amortization of regulatory assets was due to the impairment of CEI’s Extended RTC balance ($216 million) in accordance with the PUCO-approved ESP. The increase in the deferral of new regulatory assets was due to CEI’s deferral of purchased power costs as approved by the PUCO, partially offset by lower deferred MISO transmission expenses and the absence of RCP distribution deferrals that ceased at the end of 2008. Other operating costs were $52 million lower than in the previous year due to lower transmission expenses (included in the cost of power purchased from others beginning June 1, 2009) and reduced labor and contractor costs, partially offset by costs associated with the ESP for economic development and energy efficiency programs, higher pension expense and restructuring costs. The increase in general taxes was primarily due to higher property taxes.







 
125

 


THE TOLEDO EDISON COMPANY

  MANAGEMENT'S NARRATIVE
  ANALYSIS OF RESULTS OF OPERATIONS


TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain TE as their power supplier. Until December 31, 2008, TE purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that was reflected in rates approved by the PUCO. See Regulatory Matters – Ohio in our Combined Notes to the Consolidated Financial Statements for a discussion of Ohio power supply procurement issues for 2009 and beyond.

For additional information with respect to TE, please see the information contained in FirstEnergy's Management Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements and Outlook.

Results of Operations

Net income in the first nine months of 2009 decreased to $14 million from $70 million in the same period of 2008. The change resulted primarily from increased purchased power expense and the completion of transition cost recovery in 2008.

Revenues

Revenues increased slightly in the first nine months of 2009 compared to the same period of 2008 primarily due to increased retail generation revenues ($143 million) and other miscellaneous revenue ($3 million), partially offset by lower distribution revenues ($130 million) and wholesale generation revenues ($16 million).

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


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

   
Increase
 
Retail Generation KWH Sales
 
(Decrease)
 
         
Residential
   
2.4
 %
Commercial
   
30.0
 %
Industrial
   
(17.8
)%
    Net decrease in Retail Generation Sales
   
(2.7
)%

Retail Generation Revenues
 
Increase
 
   
(In millions)
 
Residential
 
$
35
 
Commercial
   
66
 
Industrial
   
42
 
    Increase in Retail Generation Revenues
 
$
143
 

The decrease in wholesale revenues was primarily due to the expiration of a sales agreement with AMP-Ohio at the end of 2008 ($10 million) and lower revenues from associated sales to NGC ($6 million) from TE's leasehold interest in Beaver Valley Unit 2.

 
126

 


Revenues from distribution throughput decreased by $130 million in the first nine months of 2009 compared to the same period of 2008 due to lower average unit prices and lower KWH deliveries for all customer classes due primarily to economic conditions. Transition charges that ceased effective January 1, 2009, with the full recovery of related costs, were partially offset by a PUCO-approved distribution rate increase (see Regulatory Matters – Ohio).

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

Distribution KWH Deliveries
 
Decrease
 
         
Residential
   
(5.2
)%
Commercial
   
(10.2
)%
Industrial
   
(12.9
)%
    Decrease in Distribution Deliveries
   
(10.3
)%

Distribution Revenues
 
Decrease
 
   
(In millions)
 
Residential
 
$
(31
)
Commercial
   
(61
)
Industrial
   
(38
)
   Decrease in Distribution Revenues
 
$
(130
)

Expenses

Total expenses increased $80 million in the first nine months of 2009 from the same period of 2008. The following table presents changes from the prior year by expense category.

Expenses – Changes
 
Increase (Decrease)
 
   
(In millions)
 
Purchased power costs
 
$
141
 
Other operating costs
   
(32
)
Provision for depreciation
   
(2
)
Amortization of regulatory assets, net
   
(27
)
Net Increase in Expenses
 
$
80
 

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

.

 
127

 

JERSEY CENTRAL POWER & LIGHT COMPANY

MANAGEMENT'S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS


JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts business in New Jersey, providing regulated electric transmission and distribution services. JCP&L also provides generation services to franchise customers electing to retain JCP&L as their power supplier. JCP&L procures electric supply to serve its BGS customers through a statewide auction process approved by the NJBPU.

For additional information with respect to JCP&L, please see the information contained in FirstEnergy's Management Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances and Outlook.

Results of Operations

Net income for the first nine months of 2009 decreased to $128 million from $153 million in the same period in 2008. The decrease was primarily due to lower revenues, partially offset by lower purchased power costs and reduced amortization of regulatory assets.

Revenues

In the first nine months of 2009, revenues decreased by $382 million, or 14%, compared with the same period of 2008. The decrease in revenues is primarily due to a decrease in retail generation revenues ($131 million), wholesale generation revenues ($208 million), and distribution revenues ($39 million) in the first nine months of 2009.

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

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

Retail Generation KWH Sales
 
Decrease
 
         
Residential
   
(5.3)
%
Commercial
   
(19.7)
%
Industrial
   
(13.7)
%
Decrease in Generation Sales
   
(11.4)
%

Retail Generation Revenues
 
 Decrease
 
   
(In millions)
 
Residential
 
$
(15)
 
Commercial
   
(104)
 
Industrial
   
(12)
 
Net Decrease in Generation Revenues
 
$
(131)
 

Wholesale generation revenues decreased $208 million in the first nine months of 2009 due to lower market prices and a decrease in sales volume from NUG purchases resulting from the termination of a NUG contract in October 2008.

Distribution revenues decreased $39 million in the first nine months of 2009 compared to the same period of 2008 due to lower KWH deliveries, reflecting weather and economic impacts in JCP&L’s service territory, partially offset by an increase in composite unit prices.

 
128

 

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

Distribution KWH Deliveries
 
Decrease
 
           
Residential
     
(5.3)
%
Commercial
     
(3.9)
%
Industrial
     
(13.1)
%
 Decrease in Distribution Deliveries
     
(5.6)
%

Distribution Revenues
 
Decrease
 
   
(In millions)
 
Residential
 
$
(25)
 
Commercial
   
(10)
 
Industrial
   
(4)
 
Decrease in Distribution Revenues
 
$
(39)
 

Expenses

Total expenses decreased by $346 million in the first nine months of 2009 compared to the same period of 2008. The following table presents changes from the prior year period by expense category:

Expenses  - Changes
 
Increase
(Decrease)
 
   
(In millions)
 
Purchased power costs
 
$
(338
)
Other operating costs
   
7
 
Provision for depreciation
   
7
 
Amortization of regulatory assets
   
(18
)
General taxes
   
(4
)
Net decrease in expenses
 
$
(346
)

Purchased power costs decreased in the first nine months of 2009 primarily due to the lower KWH sales requirements discussed above and lower unit prices due to reduced energy rates. Other operating costs increased in the first nine months of 2009 primarily due to higher expenses related to employee benefits and customer assistance programs. Depreciation expense increased due to an increase in depreciable property since the third quarter of 2008. Amortization of regulatory assets decreased in the first nine months of 2009 primarily due to the full recovery of certain regulatory assets in June 2008. General taxes decreased principally as the result of lower Transitional Energy Facility Assessment (TEFA) and sales taxes.

Other Expenses

Other expenses increased by $9 million in the first nine months of 2009 compared to the same period in 2008 primarily due to higher interest expense associated with JCP&L's $300 million Senior Notes issuance in January 2009.

Sale of Investment

On April 17, 2008, JCP&L closed on the sale of its 86-MW Forked River Power Plant to Maxim Power Corp. for $20 million, as approved by an earlier order from the NJBPU. The New Jersey Rate Counsel appealed the sale to the Appellate Division of the Superior Court of New Jersey. On July 10, 2009, the Court upheld the NJBPU’s order and the sale of the plant.







 
129

 



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. On November 3, 2009, FES, Met-Ed, Penelec and Waverly restated their partial requirements power purchase agreement for 2010. The Fourth Restated Partial Requirements Agreement continues to limit the amount of capacity resources required to be supplied by FES to 3544 MW, but requires FES to supply essentially all of Met-Ed, Penelec, and Waverly’s energy requirements in 2010 Under the new agreement, Met-Ed, Penelec, and Waverly assign 1300 MW of existing energy purchases to FES to assist it in supplying Buyers’ power supply requirements and managing congestion expenses. FES can either sell the assigned power from the third party into the market or use it to serve the Met-Ed/Penelec load. FES is responsible for obtaining additional power supplies in the event of failure of supply of the assigned energy purchase contracts. Prices for the power sold by FES were increased to $42.77 and $44.42, respectively for Met-Ed and Penelec. In addition, FES agreed to reimburse Met-Ed and Penelec, respectively, for congestion expenses and marginal losses in excess of $208 million and $79 million as billed by PJM in 2010, and associated with delivery of power by FES under the Fourth Restated Partial Requirements Agreement. The Fourth Restated Partial Requirements Agreement terminates at the end of 2010.

For additional information with respect to Met-Ed, please see the information contained in FirstEnergy's Management Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances and Outlook.

Results of Operations

Net income decreased to $37 million in the first nine months of 2009, compared to $64 million in the same period of 2008. The decrease was primarily due to increased amortization of regulatory assets, partially offset by lower other operating costs, purchased power and income taxes.

Revenues

Revenues increased by $5 million, or 0.4%, in the first nine months of 2009 compared to the same period of 2008 primarily due to higher distribution throughput revenues, partially offset by a decrease in retail generation and wholesale revenues. Wholesale revenues decreased by $7 million in the first nine months of 2009 due to lower wholesale KWH sales volume, partially offset by higher capacity prices for PJM market participants.

In the first nine months of 2009, retail generation revenues decreased $28 million due to lower KWH sales to all classes with a slight increase in composite unit prices in the residential and commercial customer classes and a slight decrease in composite unit prices in the industrial customer class. Lower KWH sales to commercial and industrial customers were principally due to economic conditions in Met-Ed’s service territory. Lower KWH sales in the residential sector were due to decreased weather-related usage, reflecting a 13.9% decrease in cooling degree days in the first nine months of 2009.

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

Retail Generation KWH Sales
 
(Decrease)
 
         
   Residential
   
(2.0
)%
   Commercial
   
(4.7
)%
   Industrial
   
(11.9
)%
   Decrease in Retail Generation Sales
   
(5.6
)%

Retail Generation Revenues
 
(Decrease)
 
   
(In millions)
 
   Residential
 
 $
(4
)
   Commercial
   
(8
)
   Industrial
   
(16
)
   Decrease in Retail Generation Revenues
 
 $
(28
)


 
130

 


In the first nine months of 2009, distribution throughput revenues increased $63 million primarily due to higher transmission rates, resulting from the annual update to Met-Ed’s TSC rider effective June 1, 2009. Decreased deliveries to commercial and industrial customers reflected the weakened economy, while decreased deliveries to residential customers were a result of the weather conditions described above.

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

Distribution KWH Deliveries
 
(Decrease)
 
         
Residential
   
(2.0
)%
Commercial
   
(4.7
)%
Industrial
   
(11.9
)%
    Decrease in Distribution Deliveries
   
(5.6
)%

Distribution Revenues
 
Increase
 
   
(In millions)
 
Residential
 
 $
32
 
Commercial
   
20
 
Industrial
   
11
 
    Increase in Distribution Revenues
 
 $
63
 

Transmission service revenues decreased by $22 million in the first nine months of 2009 compared to the same period of 2008, primarily due to decreased revenues related to Met-Ed’s Financial Transmission Rights. Met-Ed defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.

Operating Expenses

Total operating expenses increased by $44 million in the first nine months of 2009 compared to the same period of 2008. The following table presents changes from the prior year by expense category:

Expenses – Changes
 
Increase (Decrease)
 
   
(In millions)
 
Purchased power costs
 
$
(17
)
Other operating costs
   
(129
)
Provision for depreciation
   
5
 
Amortization of regulatory assets, net
   
184
 
General taxes
   
1
 
Net Increase in Expenses
 
$
44
 

The net amortization of regulatory assets increased by $184 million in the first nine months of 2009 compared to the same period of 2008 primarily due to increased transmission cost recovery reflecting lower PJM transmission service expenses and the increased transmission revenues described above. Other operating costs decreased $129 million in the first nine months of 2009 primarily due to lower transmission expenses as a result of decreased congestion costs and transmission loss expenses. Purchased power costs decreased by $17 million, or 2.5%, in the first nine months of 2009 due to reduced volumes purchased as a result of lower KWH sales requirements, partially offset by an increase in composite unit prices. Depreciation expense increased primarily due to an increase in depreciable property since the third quarter of 2008.

Other Expense

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





 
131

 



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. On November 3, 2009, FES, Met-Ed, Penelec and Waverly restated their partial requirements power purchase agreement for 2010. The Fourth Restated Partial Requirements Agreement continues to limit the amount of capacity resources required to be supplied by FES to 3544 MW, but requires FES to supply essentially all of Met-Ed, Penelec, and Waverly’s energy requirements in 2010 Under the new agreement, Met-Ed, Penelec, and Waverly assign 1300 MW of existing energy purchases to FES to assist it in supplying Buyers’ power supply requirements and managing congestion expenses. FES can either sell the assigned power from the third party into the market or use it to serve the Met-Ed/Penelec load. FES is responsible for obtaining additional power supplies in the event of failure of supply of the assigned energy purchase contracts. Prices for the power sold by FES were increased to $42.77 and $44.42, respectively for Met-Ed and Penelec. In addition, FES agreed to reimburse Met-Ed and Penelec, respectively, for congestion expenses and marginal losses in excess of $208 million and $79 million as billed by PJM in 2010, and associated with delivery of power by FES under the Fourth Restated Partial Requirements Agreement. The Fourth Restated Partial Requirements Agreement terminates at the end of 2010.

For additional information with respect to Penelec, please see the information contained in FirstEnergy's Management Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances and Outlook.

Results of Operations

Net income decreased to $49 million in the first nine months of 2009, compared to $62 million in the same period of 2008. The decrease was primarily due to lower revenues, partially offset by lower purchased power costs and decreased amortization of regulatory assets.

Revenues

Revenues decreased by $61 million, or 5.4%, in the first nine months of 2009 primarily due to lower retail generation revenues, distribution throughput revenues and transmission revenues, partially offset by higher wholesale generation revenues. Wholesale revenues increased $1 million in the first nine months of 2009, compared to the same period of 2008, primarily reflecting higher KWH sales.

In the first nine months of 2009, retail generation revenues decreased $31 million primarily due to lower KWH sales to the commercial and industrial customer classes due to weakened economic conditions; reduced KWH sales to the residential customer class were due to decreased weather-related usage, reflecting a 28.5% decrease in cooling degree days in the first nine months of 2009.

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

Retail Generation KWH Sales
 
(Decrease)
 
       
Residential
   
(1.4)
%
Commercial
   
(3.2)
%
Industrial
   
(16.2)
%
    Decrease in Retail Generation Sales
   
(6.6)
%

       
Retail Generation Revenues
 
(Decrease)
 
   
(In millions)
 
Residential
 
$
(2)
 
Commercial
   
(6)
 
Industrial
   
(23)
 
    Decrease in Retail Generation Revenues
 
$
(31)
 


 
132

 


Revenues from distribution throughput decreased $2 million in the first nine months of 2009 compared to the same period of 2008, primarily due to decreased deliveries to the commercial and industrial sectors reflecting the economic conditions in Penelec's service area. Offsetting this decrease was an increase in residential unit prices due to an increase in transmission rates, resulting from the annual update of Penelec's TSC rider effective June 1, 2009.

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

Distribution KWH Deliveries
 
(Decrease)
 
       
Residential
   
(1.4)
%
Commercial
   
(3.2)
%
Industrial
   
(15.4)
%
    Decrease in Distribution Deliveries
   
(6.6)
%

Distribution Revenues
 
Increase
(Decrease)
 
   
(In millions)
 
Residential
 
$
4
 
Commercial
   
(2
)
Industrial
   
(4
)
    Net Decrease in Distribution Revenues
 
$
(2
)

Transmission revenues decreased by $34 million in the first nine months of 2009 compared to the same period of 2008, primarily due to lower revenues related to Penelec’s Financial Transmission Rights. Penelec defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.

Operating Expenses

Total operating expenses decreased by $27 million in the first nine months of 2009 as compared with the same period of 2008. The following table presents changes from the prior year by expense category:

Expenses - Changes
 
Increase
(Decrease)
 
   
(In millions)
 
Purchased power costs
 
$
(11
)
Other operating costs
   
(5
)
Provision for depreciation
   
5
 
Amortization of regulatory assets, net
   
(11
)
General taxes
   
(5
)
Net Decrease in Expenses
 
$
(27
)

Purchased power costs decreased by $11 million, or 1.7%, in the first nine months of 2009 compared to the same period of 2008 due to reduced volume as a result of lower KWH sales requirements, partially offset by increased composite unit prices. Other operating costs decreased by $5 million in the first nine months of 2009 due primarily to reduced labor and transmission expenses and a decrease in contingency reserves based on a favorable legal ruling, partially offset by higher pension and OPEB expenses. Depreciation expense increased primarily due to an increase in depreciable property since the third quarter of 2008. The net amortization of regulatory assets decreased in the first nine months of 2009 primarily due to increased transmission cost deferrals as a result of increased net congestion costs. General taxes decreased due to lower gross receipts tax due to the reduced KWH sales mentioned above.

Other Expense

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





 
133

 

ITEM 3.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See "Management's Discussion and Analysis of Financial Condition and Results of Operations – Market Risk Information" in Item 2 above.

ITEM 4.   CONTROLS AND PROCEDURES

(a)    EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES – FIRSTENERGY

FirstEnergy's chief executive officer and chief financial officer have reviewed and evaluated the effectiveness of the registrant's disclosure controls and procedures as of the end of the period covered by this report. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, those officers have concluded that the registrant's disclosure controls and procedures were effective as of the end of the period covered by this report.

(b)    CHANGES IN INTERNAL CONTROLS

During the quarter ended September 30, 2009, there were no changes in FirstEnergy's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrant's internal control over financial reporting.

ITEM 4T. CONTROLS AND PROCEDURES – FES, OE, CEI, TE, JCP&L, MET-ED AND PENELEC

(a)    EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Each registrant's chief executive officer and chief financial officer have reviewed and evaluated the effectiveness of such registrant's disclosure controls and procedures as of the end of the period covered by this report. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, those officers have concluded that such registrant's disclosure controls and procedures were effective as of the end of the period covered by this report.

(b)    CHANGES IN INTERNAL CONTROLS

During the quarter ended September 30, 2009, there were no changes in the registrants' internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting.


 
134

 

PART II. OTHER INFORMATION

ITEM 1.   LEGAL PROCEEDINGS

Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 9 and 10 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 1A. RISK FACTORS

FirstEnergy's Annual Report on Form 10-K for the year ended December 31, 2008, and Quarterly Report on Form 10-Q for the quarter ended March 31, 2009 and June 30, 2009, include a detailed discussion of its risk factors. For the quarter ended September 30, 2009, there have been no material changes to these risk factors.

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

(c)    FirstEnergy

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

   
Period
 
   
July
 
August
 
September
 
Third Quarter
 
Total Number of Shares Purchased (a)
 
30,128
 
108,110
 
367,075
 
505,313
 
Average Price Paid per Share
 
$39.05
 
$45.21
 
$45.46
 
$45.02
 
Total Number of Shares Purchased
                 
As Part of Publicly Announced Plans
                 
or Programs
 
-
 
-
 
-
 
-
 
Maximum Number (or Approximate Dollar
                 
Value) of Shares that May Yet Be
                 
Purchased Under the Plans or Programs
 
-
 
-
 
-
 
-
 

(a)
Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock under its 2007 Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the 2007 Incentive Compensation Plan and the Executive Deferred Compensation Plan.

 
ITEM 5.   OTHER INFORMATION

On November 3, 2009, FirstEnergy Solutions Corp. (FES), Met-Ed, Penelec and Waverly executed a Fourth Restated Partial Requirements Agreement (Fourth PRA) effective January 1, 2010. The Fourth PRA supersedes the Third Restated Partial Requirements Agreement executed November 1, 2008, among the parties. The Fourth PRA also terminates the call options provided under the Third Restated Partial Requirements Agreement. The Fourth PRA continues to limit the amount of capacity resources supplied by FES to 3544 MW, but requires FES to supply essentially all of Met-Ed, Penelec, and Waverly’s (Buyers) energy requirements in 2010 Under the Fourth PRA, Met-Ed, Penelec, and Waverly assign 1300 MW of existing energy purchases from a third party, non-affiliated supplier to FES to assist it in supplying Buyers’ power supply requirements and managing congestion expenses. FES can either sell the assigned power from the third party into the market or use it to serve the Met-Ed/Penelec load. FES is responsible for obtaining additional power supplies in the event of failure of supply under the assigned energy purchase contracts. Prices for the power sold by FES were increased to $42.77 and $44.42, respectively for Met-Ed and Penelec. In addition, FES agreed to reimburse Met-Ed and Penelec, respectively, for congestion expenses and marginal losses in excess of $208 million and $79 million as billed by PJM in 2010, and associated with delivery of power by FES under the Fourth Restated Partial Requirements Agreement. The Fourth Restated Partial Requirements Agreement terminates at the end of 2010.
 
The foregoing summary does not purport to be complete and is qualified in its entirety by reference to the Fourth Restated Partial Requirements Agreements filed as an exhibit to this Form 10-Q.


 
135

 


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
 
101*
The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended September 30, 2009, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.
FES
 
 
3.1
Amended and Restated Code of Regulations of FirstEnergy Solutions Corp. effective as of August 26, 2009 (incorporated by reference to FES' Form 8-K filed on August 7, 2009 (SEC File No. 000-53742), Exhibit 3.1)
 
4.1
Indenture, dated as of August 1, 2009, between FirstEnergy Solutions Corp. and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to FES' Form 8-K filed on August 7, 2009 (SEC File No. 000-53742), Exhibit 4.1)
 
4.2
First Supplemental Indenture, dated as of August 1, 2009, between FirstEnergy Solutions Corp. and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to FES' Form 8-K filed on August 7, 2009 (SEC File No. 000-53742), Exhibit 4.2)
 
4.3
Form of 4.80% Senior Notes due 2015 (incorporated by reference to FES' Form 8-K filed on August 7, 2009 (SEC File No. 000-53742), Exhibit 4.2)
 
4.4
Form of 6.05% Senior Notes due 2021 (incorporated by reference to FES' Form 8-K filed on August 7, 2009 (SEC File No. 000-53742), Exhibit 4.2)
 
4.5
Form of 6.80% Senior Notes due 2039 (incorporated by reference to FES' Form 8-K filed on August 7, 2009 (SEC File No. 000-53742), Exhibit 4.2)
 
10.1
Registration Rights Agreement, dated August 7, 2009, among FirstEnergy Solutions Corp., and Morgan Stanley & Co. Incorporated, Barclays Capital Inc., Credit Suisse Securities (USA) LLC and RBS Securities Inc., as representatives of the initial purchasers (incorporated by reference to FES' Form 8-K filed on August 7, 2009 (SEC File No. 000-53742), Exhibit 10.1)
 
10.2
The Fourth Restated Partial Requirements Agreement
 
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
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
 
 
4.1
Ninetieth Supplemental Indenture, dated as of August 1, 2009, to The Cleveland Electric Illuminating Company’s Mortgage and Deed of Trust dated July 1, 1940 (incorporated by reference to CEI's Form 8-K filed on August 18, 2009 (SEC File No. 1-2323), Exhibit 4.1)
 
4.2
Form of First Mortgage Bonds, 5.50% Series due 2024 (incorporated by reference to CEI's Form 8-K filed on August 18, 2009 (SEC File No. 1-2323), Exhibit 4.1)
 
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

 
136

 


TE
 
 
12
Fixed charge ratios
 
15
Letter from independent registered public accounting firm
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 
32
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
JCP&L
 
 
12
Fixed charge ratios
 
15
Letter from independent registered public accounting firm
 
31.1
Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 
31.2
Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 
32
Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
Met-Ed
 
 
10.2
The Fourth Restated Partial Requirements Agreement
 
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
Penelec
 
 
4.1
Company Order, dated as of September 30, 2009 establishing the terms of the 5.20% Senior Notes due 2020 and 6.15% Senior Notes due 2038  (incorporated by reference to Penelec's Form 8-K filed on October 6, 2009 (SEC File No. 1-3522), Exhibit 4.1)
 
4.2
Form of 5.20% Senior Notes due 2020 (incorporated by reference to Penelec's Form 8-K filed on October 6, 2009 (SEC File No. 1-3522), Exhibit 4.1)
 
4.3
Form of 6.15% Senior Notes due 2038 (incorporated by reference to Penelec's Form 8-K filed on October 6, 2009 (SEC File No. 1-3522), Exhibit 4.1)
 
4.4
Supplemental Indenture No. 2, dated as of October 1, 2009, to the Indenture dated as of April 1, 2009, as amended, between Pennsylvania Electric Company and The Bank of New York Mellon, as successor trustee (incorporated by reference to Penelec's Form 8-K filed on October 6, 2009 (SEC File No. 1-3522), Exhibit 4.4)
 
4.5
 
Agreement of Resignation, Appointment and Acceptance among The Bank of New York Mellon, as Resigning Trustee, The Bank of New York Mellon Trust Company, N.A., as Successor Trustee and Pennsylvania Electric Company, dated October 1, 2009 (incorporated by reference to Penelec's Form 8-K filed on October 6, 2009 (SEC File No. 1-3522), Exhibit 4.5)
 
10.2
The Fourth Restated Partial Requirements Agreement
 
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

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

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

Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but each hereby agrees to furnish to the SEC on request any such documents.

 
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SIGNATURES



Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


November 6, 2009





 
FIRSTENERGY CORP.
 
Registrant
   
 
FIRSTENERGY SOLUTIONS CORP.
 
Registrant
   
 
OHIO EDISON COMPANY
 
Registrant
   
 
THE CLEVELAND ELECTRIC
 
ILLUMINATING COMPANY
 
Registrant
   
 
THE TOLEDO EDISON COMPANY
 
Registrant
   
 
METROPOLITAN EDISON COMPANY
 
Registrant
   
 
PENNSYLVANIA ELECTRIC COMPANY
 
Registrant



 
/s/ Harvey L. Wagner
 
Harvey L. Wagner
 
Vice President, Controller
 
and Chief Accounting Officer



 
JERSEY CENTRAL POWER & LIGHT COMPANY
 
Registrant
   
   
   
 
/s/ Kevin R. Burgess
 
Kevin R. Burgess
 
Controller
 
(Principal Accounting Officer)


 
138