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

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

For the quarterly period ended SeptemberJune 30, 20092010

OR

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

For the transition period from 
oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period fromto
 

CommissionRegistrant; State of Incorporation;I.R.S. Employer
File Number
Address; and Telephone Number
Identification No.
   
333-21011FIRSTENERGY CORP.34-1843785
 (An Ohio Corporation) 
 76 South Main Street 
 Akron, OH 44308 
 
Telephone (800)736-3402 
   
000-53742FIRSTENERGY SOLUTIONS CORP.31-1560186
 (An Ohio Corporation) 
 c/o FirstEnergy Corp. 
 76 South Main Street 
 Akron, OH 44308 
 Telephone (800)736-3402 
   
1-2578OHIO EDISON COMPANY
(An Ohio Corporation)
34-0437786
 (An Ohio Corporation)
 c/o FirstEnergy Corp. 
 76 South Main Street 
 Akron, OH 44308 
 
Telephone (800)736-3402 
   
1-2323THE CLEVELAND ELECTRIC ILLUMINATING COMPANY34-0150020
 (An Ohio Corporation) 
 c/o FirstEnergy Corp. 
 76 South Main Street 
 Akron, OH 44308 
 
Telephone (800)736-3402 
   
1-3583THE TOLEDO EDISON COMPANY34-4375005
 (An Ohio Corporation) 
 c/o FirstEnergy Corp. 
 76 South Main Street 
 Akron, OH 44308 
 
Telephone (800)736-3402 
   
1-3141JERSEY CENTRAL POWER & LIGHT COMPANY21-0485010
 (A New Jersey Corporation) 
 c/o FirstEnergy Corp. 
 76 South Main Street 
 Akron, OH 44308 
 
Telephone (800)736-3402 
   
1-446METROPOLITAN EDISON COMPANY23-0870160
 (A Pennsylvania Corporation) 
 c/o FirstEnergy Corp. 
 76 South Main Street 
 Akron, OH 44308 
 
Telephone (800)736-3402 
   
1-3522PENNSYLVANIA ELECTRIC COMPANY25-0718085
 (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.

YesYes (X)þ No(  )o
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).

YesYes (X)þ No(  )o
FirstEnergy Corp.

YesYes (  )o No(  )o
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“large accelerated filer," "accelerated filer"” “accelerated filer” and "smaller“smaller reporting company"company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filerþ
(X)
FirstEnergy Corp.
Accelerated Filero
(  )
N/A
Non-accelerated Filer (Do
not check if a smaller
reporting company)þ
(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 Companyo
Company
(  )
N/A

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

YesYes (  )o No(X)þ
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'sissuer’s classes of common stock, as of the latest practicable date:


 
OUTSTANDING
CLASS
AS OF Novembe 6, 2009JULY 31, 2010
FirstEnergy Corp., $0.10$10 par value304,835, 407304,835,407
FirstEnergy Solutions Corp., no par value7
Ohio Edison Company, no par value60
The Cleveland Electric Illuminating Company, no par value67,930,743
The Toledo Edison Company, $5 par value29,402,054
Jersey Central Power & Light Company, $10 par value13,628,447
Metropolitan Edison Company, no par value859,500
Pennsylvania Electric Company, $20 par value4,427,577

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.

FirstEnergy Web Site
Each of the registrants’ Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are also made available free of charge on or through FirstEnergy’s internet web site at www.firstenergycorp.com.
These reports are posted on the web site as soon as reasonably practicable after they are electronically filed with the SEC. Additionally, the registrants routinely post important information on the web site and recognize the web site is a channel of distribution to reach public investors and as a means of disclosing material non-public information for complying with disclosure obligations under SEC Regulation FD. Information contained on FirstEnergy’s web site shall not be deemed incorporated into, or to be part of, this report.
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 pending matters in Ohio, Companies associated with the distribution rate case.Pennsylvania and New Jersey.
·
Business and regulatory impacts from ATSI’s realignment into PJM.
 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.recover regulatory assets or increased costs.
· 
OperatingOperation 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 proposed rules promulgated by EPA on July 6, 2010, in response to 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.rules.
·
 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 similar 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.
· 
Ultimate resolution of Met-Ed’s and Penelec’s transmission service chargeTSC 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.standards and energy efficiency mandates.
·
 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 declinestate of the national and regional economyeconomies and its impactassociated impacts on the registrants’ major industrial and commercial customers.
·
 Issues concerning the soundness of financial institutions and counterparties with which the registrants do business.
·
The expected timing and likelihood of completion of the proposed merger with Allegheny Energy, Inc., including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the proposed merger that could reduce anticipated benefits or cause the parties to abandon the merger, the diversion of management’s time and attention from FirstEnergy’s ongoing business during this time period, the ability to maintain relationships with customers, employees or suppliers as well as the ability to successfully integrate the businesses and realize cost savings and any other synergies and the risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect.
 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-ivPage 
    
iii-v
  
    
FirstEnergy Corp.
  
    
1 
 
2 
 
3 
 
4 
    
FirstEnergy Solutions Corp.
  
    
5 
 
6 
 
7 
    
Ohio Edison Company
  
    
8 
 
9 
 
10 
    
The Cleveland Electric Illuminating Company
  
    
11 
 
12 
 
13 
    
The Toledo Edison Company
  
    
14 
 
15 
 
16 
    
Jersey Central Power & Light Company
  
    
17 
 
18 
 
19 
    
Metropolitan Edison Company
  
    
20 
 
21 
 
22 
    
Pennsylvania Electric Company
  
    
23 
 Consolidated Balance Sheets
24
Consolidated Statements of Cash Flows
25

i


TABLE OF CONTENTS (Cont'd)


Pages
   
26-65
  
Report of Independent Registered Public Accounting Firm24 
  
FirstEnergy Corp.
66
FirstEnergy Solutions Corp.Consolidated Statements of Cash Flows
6725
Ohio Edison  CompanyExhibit 12
68
The Cleveland Electric Illuminating CompanyExhibit 31.1
69
The Toledo Edison CompanyExhibit 31.2
70
Jersey Central Power & Light CompanyExhibit 32
71
Metropolitan Edison CompanyEX-101 INSTANCE DOCUMENT
72
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

i


TABLE OF CONTENTS (Cont’d)
Pennsylvania Electric Company
73
  Page
26
74-11865
  
Management'sManagement’s Narrative Analysis of Results of Operations
 
  
119-121103
122-123106
124-125108
126-127110
128-129112
Metropolitan Edison Company
130-131
Pennsylvania Electric Company
132-133
  
114
116
134118
   
134118
  
134
  
Part II.     Other Information118 
   
Item 1.    Legal ProceedingsPart II. Other Information
135
   
135119
  
119
135119
  
Item 5.    Other Information    135
  
119
136-137120

ii





ii


GLOSSARY OF TERMS

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

ATSIAmerican Transmission Systems, Incorporated, owns and operates transmission facilities
CEIThe Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
FENOCFirstEnergy Nuclear Operating Company, operates nuclear generating facilities
FESFirstEnergy Solutions Corp., provides energy-related products and services
FESCFirstEnergy Service Company, provides legal, financial and other corporate support services
FEVFirstEnergy Ventures Corp., invests in certain unregulated enterprises and business ventures
FGCOFirstEnergy Generation Corp., owns and operates non-nuclear generating facilities
FirstEnergyFirstEnergy 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&LJersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
JCP&L Transition
   Funding
Met-Ed
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-EdMetropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
NGCFirstEnergy Nuclear Generation Corp., owns nuclear generating facilities
OEOhio Edison Company, an Ohio electric utility operating subsidiary
Ohio CompaniesCEI, OE and TE
PenelecPennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
PennPennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
Pennsylvania CompaniesMet-Ed, Penelec and Penn
PNBVPNBV Capital Trust, a special purpose entity created by OE in 1996
Shelf RegistrantsShippingportOE, CEI, TE, JCP&L, Met-Ed and Penelec
ShippingportShippingport 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
TEThe Toledo Edison Company, an Ohio electric utility operating subsidiary
UtilitiesOE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec
WaverlyThe 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:
 
The following abbreviations and acronyms are used to identify frequently used terms in this report:
  
AEPAmerican Electric Power Company, Inc.
ALJAdministrative Law Judge
AMP-OhioAOCLAmerican Municipal Power-Ohio, Inc.
AOCLAccumulated Other Comprehensive Loss
AQCAir Quality Control
AROAsset Retirement Obligation
BGS
CAA
Basic Generation Service
CAA
Clean Air Act
CAIRClean Air Interstate Rule
CAMRClean Air Mercury Rule
CBPCompetitive Bid Process
CO2
Carbon Dioxide
CTCCompetitive Transition Charge
DOEUnited States Department of Energy
DOJUnited States Department of Justice
DPADepartment of the Public Advocate, Division of Rate Counsel (New Jersey)
EDCPExecutive Deferred Compensation Plan
EE&CEnergy Efficiency and Conservation
EMAACEastern Mid-Atlantic Area Council
EMPEnergy Master Plan
EPAUnited States Environmental Protection Agency
EPACTEPRIEnergy Policy Act of 2005Electric Power Research Institute

iii


GLOSSARY OF TERMS, Cont’d.
ESPElectric Security Plan
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
FMBFirst Mortgage Bond
FPAFederal Power Act
FRRFixed Resource Requirement
GAAPGenerally Accepted Accounting Principles Generally Accepted in the United States
GHGGreenhouse Gases

iii


GLOSSARY OF TERMS, Cont'd.

IRSInternal Revenue Service
JOAJoint Operating Agreement
kVKilovolt
KWHKilowatt-hours
LEDLight-emittingLight-Emitting Diode
LIBORLOCLondon Interbank Offered Rate
LOCLetter of Credit
MAACMid-Atlantic Area Council
MACTMaximum Achievable Control Technology
MDPSCMaryland Public Service Commission
MISOMidwest Independent Transmission System Operator, Inc.
Moody'sMoody’sMoody'sMoody’s Investors Service, Inc.
MROMarket Rate Offer
MWMegawatts
MWHMegawatt-hours
NAAQSNational Ambient Air Quality Standards
NERCNorth American Electric Reliability Corporation
NJBPUNew Jersey Board of Public Utilities
NNSRNon-Attainment New Source Review
NOACNorthwest Ohio Aggregation Coalition
NOPECNortheast Ohio Public Energy Council
NOVNotice of Violation
NOX
Nitrogen Oxide
NRCNuclear Regulatory Commission
NSRNew Source Review
NUGNon-Utility Generation
NUGCNon-Utility Generation Charge
NYMEXOCINew York Mercantile Exchange
OCIOther Comprehensive Income
OPEBOther Post-Employment Benefits
OVECOhio Valley Electric Corporation
PCRBPollution Control Revenue Bond
PJMPJM Interconnection L. L. C.
PLRPOLR
Provider of Last Resort; an electric utility'sutility’s obligation to provide generation service to customers
whose alternative supplier fails to deliver service
PPUCPennsylvania Public Utility Commission
PSCWVPublic Service Commission of West Virginia
PSAPower Supply Agreement
PSDPrevention of Significant Deterioration
PPUCPennsylvania Public Utility Commission
PUCOPublic Utilities Commission of Ohio
QSPERCPQualifying Special-Purpose Entity
RCPRate Certainty Plan
RECsRenewable Energy Credits
RFPRequest for Proposal
RPMReliability Pricing Model
RTEPRegional Transmission Expansion Plan
RTCRegulatory Transition Charge
RTORegional Transmission Organization
S&PStandard & Poor'sPoor’s Ratings Service
SB221Amended Substitute Senate Bill 221
SBCSocietal Benefits Charge

iv


GLOSSARY OF TERMS, Cont’d.
SECU.S. Securities and Exchange Commission
SECASIPSeams Elimination Cost Adjustment
SIPState Implementation Plan(s) Under the Clean Air Act
SNCRSelective Non-Catalytic Reduction
SO2
Sulfur Dioxide
TBCTransition Bond Charge
TMI-2Three Mile Island Unit 2
TSCTransmission Service Charge
VEROVIEVoluntary Enhanced Retirement OptionVariable Interest Entity
VSCCVirginia State Corporation Commission
VIEVariable Interest Entity

v



FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
                 
  Three Months  Six Months 
  Ended June 30  Ended June 30 
  2010  2009  2010  2009 
  (In millions, except per share amounts) 
REVENUES:
                
Electric utilities $2,373  $2,791  $4,916  $5,811 
Unregulated businesses  755   480   1,511   794 
             
Total revenues*  3,128   3,271   6,427   6,605 
             
                 
EXPENSES:
                
Fuel  350   276   684   588 
Purchased power  1,052   1,024   2,290   2,167 
Other operating expenses  673   612   1,374   1,439 
Provision for depreciation  190   185   383   362 
Amortization of regulatory assets  161   233   373   642 
Deferral of new regulatory assets     (45)     (136)
General taxes  176   184   381   395 
             
Total expenses  2,602   2,469   5,485   5,457 
             
                 
OPERATING INCOME
  526   802   942   1,148 
             
                 
OTHER INCOME (EXPENSE):
                
Investment income  31   27   47   16 
Interest expense  (207)  (206)  (420)  (400)
Capitalized interest  40   33   81   61 
             
Total other expense  (136)  (146)  (292)  (323)
             
                 
INCOME BEFORE INCOME TAXES
  390   656   650   825 
                 
INCOME TAXES
  134   248   245   302 
             
                 
NET INCOME
  256   408   405   523 
                 
Noncontrolling interest loss  (9)  (6)  (15)  (10)
             
                 
EARNINGS AVAILABLE TO FIRSTENERGY CORP.
 $265  $414  $420  $533 
             
                 
BASIC EARNINGS PER SHARE OF COMMON STOCK
 $0.87  $1.36  $1.38  $1.75 
             
                 
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
  304   304   304   304 
             
                 
DILUTED EARNINGS PER SHARE OF COMMON STOCK
 $0.87  $1.36  $1.37  $1.75 
             
                 
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
  305   305   305   306 
             
                 
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK
 $  $  $0.55  $0.55 
             
*Includes excise tax collections of $99 million and $95 million in the three months ended June 30, 2010 and 2009, respectively, and $208 million and $204 million in the six months ended June 30, 2010 and 2009, respectively.
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

1


FIRSTENERGY CORP.
iv

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
                 
  Three Months  Six Months 
  Ended June 30  Ended June 30 
  2010  2009  2010  2009 
  (In millions) 
                 
NET INCOME
 $256  $408  $405  $523 
             
                 
OTHER COMPREHENSIVE INCOME:
                
Pension and other postretirement benefits  17   469   30   504 
Unrealized gain on derivative hedges  6   23   10   38 
Change in unrealized gain on available-for-sale securities  6   37   12   32 
             
Other comprehensive income  29   529   52   574 
Income tax expense related to other comprehensive income  9   227   16   242 
             
Other comprehensive income, net of tax  20   302   36   332 
             
                 
COMPREHENSIVE INCOME
  276   710   441   855 
                 
COMPREHENSIVE LOSS ATTRIBUTABLE TO NONCONTROLLING INTEREST
  (9)  (6)  (15)  (10)
             
                 
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP.
 $285  $716  $456  $865 
             
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

2


FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)

         
  June 30,  December 31, 
  2010  2009 
  (In millions) 
ASSETS
        
         
CURRENT ASSETS:
        
Cash and cash equivalents $281  $874 
Receivables-        
Customers (less allowances of $33 million in 2010 and 2009)  1,409   1,244 
Other (less allowances of $7 million in 2010 and 2009)  146   153 
Materials and supplies, at average cost  675   647 
Prepaid taxes  397   248 
Other  206   154 
       
   3,114   3,320 
       
PROPERTY, PLANT AND EQUIPMENT:
        
In service  28,274   27,826 
Less — Accumulated provision for depreciation  11,724   11,397 
       
   16,550   16,429 
Construction work in progress  3,000   2,735 
       
   19,550   19,164 
       
INVESTMENTS:
        
Nuclear plant decommissioning trusts  1,880   1,859 
Investments in lease obligation bonds  486   543 
Other  589   621 
       
   2,955   3,023 
       
DEFERRED CHARGES AND OTHER ASSETS:
        
Goodwill  5,575   5,575 
Regulatory assets  2,313   2,356 
Power purchase contract asset  134   200 
Other  825   666 
       
   8,847   8,797 
       
  $34,466  $34,304 
       
LIABILITIES AND CAPITALIZATION
        
         
CURRENT LIABILITIES:
        
Currently payable long-term debt $1,571  $1,834 
Short-term borrowings  1,463   1,181 
Accounts payable  848   829 
Accrued taxes  256   314 
Other  907   1,130 
       
   5,045   5,288 
       
CAPITALIZATION:
        
Common stockholders’ equity-        
Common stock, $0.10 par value, authorized 375,000,000 shares- 304,835,407 shares outstanding  31   31 
Other paid-in capital  5,440   5,448 
Accumulated other comprehensive loss  (1,379)  (1,415)
Retained earnings  4,747   4,495 
       
Total common stockholders’ equity  8,839   8,559 
Noncontrolling interest  (20)  (2)
       
Total equity  8,819   8,557 
Long-term debt and other long-term obligations  11,861   11,908 
       
   20,680   20,465 
       
NONCURRENT LIABILITIES:
        
Accumulated deferred income taxes  2,710   2,468 
Retirement benefits  1,531   1,534 
Asset retirement obligations  1,372   1,425 
Deferred gain on sale and leaseback transaction  976   993 
Power purchase contract liability  691   643 
Lease market valuation liability  239   262 
Other  1,222   1,226 
       
   8,741   8,551 
       
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 8)
        
  $34,466  $34,304 
       
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. 
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

3


FIRSTENERGY CORP.
1

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

         
  Six Months Ended 
  June 30 
  2010  2009 
  (In millions) 
CASH FLOWS FROM OPERATING ACTIVITIES:
        
Net Income $405  $523 
Adjustments to reconcile net income to net cash from operating activities-        
Provision for depreciation  383   362 
Amortization of regulatory assets  373   642 
Deferral of new regulatory assets     (136)
Nuclear fuel and lease amortization  76   52 
Deferred purchased power and other costs  (146)  (135)
Deferred income taxes and investment tax credits, net  159   69 
Investment impairment  19   39 
Deferred rents and lease market valuation liability  (62)  (59)
Stock-based compensation  (6)  (2)
Accrued compensation and retirement benefits  (27)  (93)
Interest rate swap transactions  43    
Commodity derivative transactions, net  (29)  18 
Cash collateral received (paid), net  (63)  48 
Decrease (increase) in operating assets-        
Receivables  (156)  32 
Materials and supplies  (17)  6 
Prepayments and other current assets  (81)  (179)
Increase (decrease) in operating liabilities-        
Accounts payable  18   (11)
Accrued taxes  (58)  (101)
Other  27   27 
       
Net cash provided from operating activities  858   1,102 
       
         
CASH FLOWS FROM FINANCING ACTIVITIES:
        
New Financing-        
Long-term debt     1,679 
Short-term borrowings, net  281    
Redemptions and Repayments-        
Long-term debt  (407)  (881)
Common stock dividend payments  (335)  (335)
Other  (23)  (37)
       
Net cash provided from (used for) financing activities  (484)  426 
       
         
CASH FLOWS FROM INVESTING ACTIVITIES:
        
Property additions  (997)  (1,143)
Proceeds from asset sales  116   19 
Sales of investment securities held in trusts  1,915   1,001 
Purchases of investment securities held in trusts  (1,934)  (1,041)
Customer acquisition costs  (105)   
Cash investments  59   40 
Other  (21)  (49)
       
Net cash used for investing activities  (967)  (1,173)
       
         
Net change in cash and cash equivalents  (593)  355 
Cash and cash equivalents at beginning of period  874   545 
       
Cash and cash equivalents at end of period $281  $900 
       

The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

4


FIRSTENERGY SOLUTIONS CORP.
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.                
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                 
  Three Months Ended  Six Months Ended 
  June 30  June 30 
  2010  2009  2010  2009 
  (In thousands) 
REVENUES:
                
Electric sales to affiliates $538,545  $839,751  $1,145,847  $1,732,441 
Electric sales to non-affiliates  728,803   205,379   1,397,488   485,125 
Other  47,326   296,022   159,432   349,692 
             
Total revenues  1,314,674   1,341,152   2,702,767   2,567,258 
             
                 
EXPENSES:
                
Fuel  342,411   270,309   670,632   576,467 
Purchased power from affiliates  68,898   51,249   129,851   114,456 
Purchased power from non-affiliates  298,820   185,613   749,035   345,955 
Other operating expenses  303,895   278,264   608,406   585,620 
Provision for depreciation  63,319   65,548   126,237   126,921 
General taxes  22,272   21,285   49,018   44,661 
             
Total expenses  1,099,615   872,268   2,333,179   1,794,080 
             
                 
OPERATING INCOME
  215,059   468,884   369,588   773,178 
             
                 
OTHER INCOME (EXPENSE):
                
Investment income (loss)  13,366   5,643   14,083   (23,231)
Miscellaneous income  4,393   7,622   5,703   10,133 
Interest expense to affiliates  (2,560)  (3,315)  (4,865)  (6,294)
Interest expense — other  (51,372)  (26,271)  (101,016)  (48,798)
Capitalized interest  23,905   14,028   43,595   24,106 
             
Total other expense  (12,268)  (2,293)  (42,500)  (44,084)
             
                 
INCOME BEFORE INCOME TAXES
  202,791   466,591   327,088   729,094 
                 
INCOME TAXES
  68,866   169,189   113,237   261,011 
             
                 
NET INCOME
  133,925   297,402   213,851   468,083 
             
                 
OTHER COMPREHENSIVE INCOME:
                
Pension and other postretirement benefits  885   72,121   (8,949)  74,689 
Unrealized gain on derivative hedges  3,017   15,041   4,291   26,057 
Change in unrealized gain on available-for-sale securities  6,060   39,504   11,088   38,027 
             
Other comprehensive income  9,962   126,666   6,430   138,773 
Income tax expense related to other comprehensive income  3,544   50,625   2,204   55,334 
             
Other comprehensive income, net of tax  6,418   76,041   4,226   83,439 
             
                 
TOTAL COMPREHENSIVE INCOME
 $140,343  $373,443  $218,077  $551,522 
             
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

5


FIRSTENERGY SOLUTIONS CORP.
2

CONSOLIDATED BALANCE SHEETS
(Unaudited)
         
  June 30,  December 31, 
  2010  2009 
  (In thousands) 
ASSETS
        
         
CURRENT ASSETS:
        
Cash and cash equivalents $11  $12 
Receivables-        
Customers (less accumulated provisions of $14,523,000 and $12,041,000, respectively, for uncollectible accounts)  315,178   195,107 
Associated companies  354,127   318,561 
Other (less accumulated provisions of $6,702,000 for uncollectible accounts)  36,392   51,872 
Notes receivable from associated companies  173,931   805,103 
Materials and supplies, at average cost  578,521   539,541 
Prepayments and other  172,514   107,782 
       
   1,630,674   2,017,978 
       
PROPERTY, PLANT AND EQUIPMENT:
        
In service  10,500,405   10,357,632 
Less — Accumulated provision for depreciation  4,695,180   4,531,158 
       
   5,805,225   5,826,474 
Construction work in progress  2,622,865   2,423,446 
       
   8,428,090   8,249,920 
       
INVESTMENTS:
        
Nuclear plant decommissioning trusts  1,107,594   1,088,641 
Other  7,965   22,466 
       
   1,115,559   1,111,107 
       
DEFERRED CHARGES AND OTHER ASSETS:
        
Accumulated deferred income tax benefits     86,626 
Customer intangibles  118,219   16,566 
Goodwill  24,248   24,248 
Property taxes  50,125   50,125 
Unamortized sales and leaseback costs  77,646   72,553 
Other  128,315   121,665 
       
   398,553   371,783 
       
  $11,572,876  $11,750,788 
       
LIABILITIES AND CAPITALIZATION
        
         
CURRENT LIABILITIES:
        
Currently payable long-term debt $1,381,783  $1,550,927 
Short-term borrowings-        
Associated companies  85,128   9,237 
Other  100,000   100,000 
Accounts payable-        
Associated companies  412,507   466,078 
Other  236,720   245,363 
Accrued taxes  109,082   83,158 
Other  369,086   359,057 
       
   2,694,306   2,813,820 
       
CAPITALIZATION:
        
Common stockholders’ equity-        
Common stock, without par value, authorized 750 shares, 7 shares outstanding  1,467,158   1,468,423 
Accumulated other comprehensive loss  (98,775)  (103,001)
Retained earnings  2,363,000   2,149,149 
       
Total common stockholders’ equity  3,731,383   3,514,571 
Long-term debt and other long-term obligations  2,585,918   2,711,652 
       
   6,317,301   6,226,223 
       
NONCURRENT LIABILITIES:
        
Deferred gain on sale and leaseback transaction  976,012   992,869 
Accumulated deferred investment tax credits  56,310   58,396 
Asset retirement obligations  863,409   921,448 
Retirement benefits  223,853   204,035 
Property taxes  50,125   50,125 
Lease market valuation liability  239,447   262,200 
Other  152,113   221,672 
       
   2,561,269   2,710,745 
       
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 8)
        
  $11,572,876  $11,750,788 
       

The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

6


FIRSTENERGY SOLUTIONS CORP.
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.     
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
         
  Six Months Ended 
  June 30 
  2010  2009 
  (In thousands) 
CASH FLOWS FROM OPERATING ACTIVITIES:
        
Net Income $213,851  $468,083 
Adjustments to reconcile net income to net cash from operating activities-        
Provision for depreciation  126,237   126,921 
Nuclear fuel and lease amortization  78,324   53,265 
Deferred rents and lease market valuation liability  (59,254)  (55,493)
Deferred income taxes and investment tax credits, net  113,978   63,309 
Investment impairment  19,093   36,154 
Accrued compensation and retirement benefits  7,132   (10,594)
Commodity derivative transactions, net  (29,308)  17,688 
Gain on asset sales  (1,021)  (9,635)
Cash collateral, net  (38,211)  40,471 
Decrease (increase) in operating assets-        
Receivables  (192,792)  179,373 
Materials and supplies  (28,470)  16,609 
Prepayments and other current assets  24,518   7,555 
Increase (decrease) in operating liabilities-        
Accounts payable  (31,610)  (102,907)
Accrued taxes  (8,462)  (14,333)
Accrued interest  (457)  1,871 
Other  24,907   (6,121)
       
Net cash provided from operating activities  218,455   812,216 
       
         
CASH FLOWS FROM FINANCING ACTIVITIES:
        
New Financing-        
Long-term debt     681,675 
Short-term borrowings, net  75,891   145,009 
Redemptions and Repayments-        
Long-term debt  (295,037)  (622,853)
Other  (686)   
       
Net cash provided from (used for) financing activities  (219,832)  203,831 
       
         
CASH FLOWS FROM INVESTING ACTIVITIES:
        
Property additions  (566,187)  (634,967)
Proceeds from asset sales  115,657   15,771 
Sales of investment securities held in trusts  956,813   537,078 
Purchases of investment securities held in trusts  (978,785)  (550,730)
Loans from (to) associated companies, net  631,172   (241,170)
Customer acquisition costs  (104,795)   
Leasehold improvement payments to associated companies  (51,204)   
Other  (1,295)  (22,034)
       
Net cash provided from (used for) investing activities  1,376   (896,052)
       
         
Net change in cash and cash equivalents  (1)  119,995 
Cash and cash equivalents at beginning of period  12   39 
       
Cash and cash equivalents at end of period $11  $120,034 
       
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

7


OHIO EDISON COMPANY
3

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                 
  Three Months Ended  Six Months Ended 
  June 30  June 30 
  2010  2009  2010  2009 
  (In thousands) 
STATEMENTS OF INCOME
                
                 
REVENUES:
                
Electric sales $415,437  $647,224  $895,362  $1,367,235 
Excise and gross receipts tax collections  23,949   24,948   52,424   53,928 
             
Total revenues  439,386   672,172   947,786   1,421,163 
             
                 
EXPENSES:
                
Purchased power from affiliates  114,414   314,870   250,271   647,206 
Purchased power from non-affiliates  98,462   98,330   210,513   236,143 
Other operating expenses  88,275   111,938   177,130   269,768 
Provision for depreciation  22,014   21,996   43,894   43,509 
Amortization of regulatory assets, net  9,424   22,295   38,769   42,506 
General taxes  43,362   43,903   90,854   93,023 
             
Total expenses  375,951   613,332   811,431   1,332,155 
             
                 
OPERATING INCOME
  63,435   58,840   136,355   89,008 
             
                 
OTHER INCOME (EXPENSE):
                
Investment income  6,309   10,149   11,553   19,511 
Miscellaneous income  1,295   2,681   1,003   1,871 
Interest expense  (22,155)  (21,469)  (44,465)  (44,756)
Capitalized interest  295   279   503   499 
             
Total other expense  (14,256)  (8,360)  (31,406)  (22,875)
             
                 
INCOME BEFORE INCOME TAXES
  49,179   50,480   104,949   66,133 
                 
INCOME TAXES
  11,856   16,852   31,465   20,857 
             
                 
NET INCOME
  37,323   33,628   73,484   45,276 
             
                 
Noncontrolling interest income  130   143   262   289 
             
                 
EARNINGS AVAILABLE TO PARENT
 $37,193  $33,485  $73,222  $44,987 
             
                 
STATEMENTS OF COMPREHENSIVE INCOME
                
                 
NET INCOME
 $37,323  $33,628  $73,484  $45,276 
             
                 
OTHER COMPREHENSIVE INCOME (LOSS):
                
Pension and other postretirement benefits  322   89,864   4,337   95,602 
Change in unrealized gain on available-for-sale securities  520   728   811   (1,981)
             
Other comprehensive income  842   90,592   5,148   93,621 
Income tax expense (benefit) related to other                
comprehensive income  (26)  37,310   667   37,839 
             
Other comprehensive income, net of tax  868   53,282   4,481   55,782 
             
                 
COMPREHENSIVE INCOME
  38,191   86,910   77,965   101,058 
                 
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
  130   143   262   289 
             
                 
COMPREHENSIVE INCOME AVAILABLE TO PARENT
 $38,061  $86,767  $77,703  $100,769 
             
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

8


OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
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.        
         
  June 30,  December 31, 
  2010  2009 
  (In thousands) 
ASSETS
        
CURRENT ASSETS:
        
Cash and cash equivalents $51,679  $324,175 
Receivables-        
Customers (less accumulated provisions of $4,685,000 and $5,119,000, respectively, for uncollectible accounts)  202,983   209,384 
Associated companies  68,005   98,874 
Other (less accumulated provisions of $6,000 and $18,000, respectively, for uncollectible accounts)  13,065   14,155 
Notes receivable from associated companies  106,232   118,651 
Prepayments and other  14,748   15,964 
       
   456,712   781,203 
       
UTILITY PLANT:
        
In service  3,086,689   3,036,467 
Less — Accumulated provision for depreciation  1,189,802   1,165,394 
       
   1,896,887   1,871,073 
Construction work in progress  36,866   31,171 
       
   1,933,753   1,902,244 
       
OTHER PROPERTY AND INVESTMENTS:
        
Investment in lease obligation bonds  204,812   216,600 
Nuclear plant decommissioning trusts  126,405   120,812 
Other  96,633   96,861 
       
   427,850   434,273 
       
DEFERRED CHARGES AND OTHER ASSETS:
        
Regulatory assets  422,559   465,331 
Pension assets  36,199   19,881 
Property taxes  67,037   67,037 
Unamortized sales and leaseback costs  32,626   35,127 
Other  17,765   39,881 
       
   576,186   627,257 
       
  $3,394,501  $3,744,977 
       
LIABILITIES AND CAPITALIZATION
        
CURRENT LIABILITIES:
        
Currently payable long-term debt $7,975  $2,723 
Short-term borrowings-        
Associated companies     92,863 
Other  653   807 
Accounts payable-        
Associated companies  54,891   102,763 
Other  31,087   40,423 
Accrued taxes  55,976   81,868 
Accrued interest  25,639   25,749 
Other  79,382   81,424 
       
   255,603   428,620 
       
CAPITALIZATION:
        
Common stockholder’s equity-        
Common stock, without par value, authorized 175,000,000 shares - 60 shares outstanding  949,822   1,154,797 
Accumulated other comprehensive loss  (159,096)  (163,577)
Retained earnings  58,112   29,890 
       
Total common stockholder’s equity  848,838   1,021,110 
Noncontrolling interest  6,100   6,442 
       
Total equity  854,938   1,027,552 
Long-term debt and other long-term obligations  1,152,303   1,160,208 
       
   2,007,241   2,187,760 
       
NONCURRENT LIABILITIES:
        
Accumulated deferred income taxes  678,669   660,114 
Accumulated deferred investment tax credits  10,882   11,406 
Retirement benefits  171,056   174,925 
Asset retirement obligations  81,941   85,926 
Other  189,109   196,226 
       
   1,131,657   1,128,597 
       
COMMITMENTS AND CONTINGENCIES (Note 8)
        
  $3,394,501  $3,744,977 
       

The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

9


OHIO EDISON COMPANY
4

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

         
  Six Months Ended 
  June 30 
  2010  2009 
  (In thousands) 
CASH FLOWS FROM OPERATING ACTIVITIES:
        
Net Income $73,484  $45,276 
Adjustments to reconcile net income to net cash from operating activities-        
Provision for depreciation  43,894   43,509 
Amortization of regulatory assets, net  38,769   42,506 
Purchased power cost recovery reconciliation  (1,514)  11,068 
Amortization of lease costs  (4,619)  (4,540)
Deferred income taxes and investment tax credits, net  4,964   (11,252)
Accrued compensation and retirement benefits  (16,154)  (4,593)
Accrued regulatory obligations  (2,309)  18,350 
Electric service prepayment programs     (4,603)
Cash collateral from suppliers  1,215   6,380 
Decrease (increase) in operating assets-        
Receivables  49,250   (16,509)
Prepayments and other current assets  5,072   (6,290)
Increase (decrease) in operating liabilities-        
Accounts payable  (57,208)  (4,820)
Accrued taxes  (25,685)  (19,523)
Accrued interest  (110)  36 
Other  (4)  10,086 
       
Net cash provided from operating activities  109,045   105,081 
       
         
CASH FLOWS FROM FINANCING ACTIVITIES:
        
New Financing-        
Long-term debt     100,000 
Short-term borrowings, net     114,617 
Redemptions and Repayments-        
Long-term debt  (2,957)  (100,984)
Short-term borrowings, net  (93,017)   
Common stock dividend payments  (250,000)  (125,000)
Other  (881)  (1,627)
       
Net cash used for financing activities  (346,855)  (12,994)
       
         
CASH FLOWS FROM INVESTING ACTIVITIES:
        
Property additions  (71,698)  (69,512)
Lease improvement payments from associated companies  18,375    
Sales of investment securities held in trusts  59,804   24,941 
Purchases of investment securities held in trusts  (64,063)  (30,877)
Loan repayments from associated companies, net  12,420   51,803 
Cash investments  11,774   7,929 
Other  (1,298)  1,098 
       
Net cash used for investing activities  (34,686)  (14,618)
       
         
Net change in cash and cash equivalents  (272,496)  77,469 
Cash and cash equivalents at beginning of period  324,175   146,343 
       
Cash and cash equivalents at end of period $51,679  $223,812 
       
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.                
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

10


THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                 
  Three Months Ended  Six Months Ended 
  June 30  June 30 
  2010  2009  2010  2009 
  (In thousands) 
STATEMENTS OF INCOME
                
REVENUES:
                
Electric sales $280,180  $458,287  $592,677  $889,692 
Excise tax collections  15,495   16,799   33,068   35,119 
             
Total revenues  295,675   475,086   625,745   924,811 
             
                 
EXPENSES:
                
Purchased power from affiliates  83,532   243,499   178,497   482,371 
Purchased power from non-affiliates  48,541   49,414   100,367   121,160 
Other operating expenses  28,937   39,177   60,172   104,007 
Provision for depreciation  18,336   17,852   36,447   36,132 
Amortization of regulatory assets  30,807   29,580   75,946   286,317 
Deferral of new regulatory assets     (39,771)     (134,587)
General taxes  28,840   36,856   67,329   74,997 
             
Total expenses  238,993   376,607   518,758   970,397 
             
                 
OPERATING INCOME (LOSS)
  56,682   98,479   106,987   (45,586)
             
                 
OTHER INCOME (EXPENSE):
                
Investment income  6,605   7,614   14,152   16,034 
Miscellaneous expense  675   798   1,257   2,792 
Interest expense  (33,262)  (32,757)  (66,883)  (66,079)
Capitalized interest  7   51   33   118 
             
Total other expense  (25,975)  (24,294)  (51,441)  (47,135)
             
                 
INCOME (LOSS) BEFORE INCOME TAXES
  30,707   74,185   55,546   (92,721)
                 
INCOME TAX EXPENSE (BENEFIT)
  8,785   26,461   19,628   (35,045)
             
                 
NET INCOME (LOSS)
  21,922   47,724   35,918   (57,676)
             
                 
Noncontrolling interest income  366   419   785   877 
             
                 
EARNINGS (LOSS) AVAILABLE TO PARENT
 $21,556  $47,305  $35,133  $(58,553)
             
                 
STATEMENTS OF COMPREHENSIVE INCOME
                
                 
NET INCOME (LOSS)
 $21,922  $47,724  $35,918  $(57,676)
             
                 
OTHER COMPREHENSIVE INCOME (LOSS):
                
Pension and other postretirement benefits  3,228   43,903   (19,357)  47,870 
Income tax expense (benefit) related to other comprehensive income  976   17,936   (7,301)  19,306 
             
Other comprehensive income (loss), net of tax  2,252   25,967   (12,056)  28,564 
             
                 
COMPREHENSIVE INCOME (LOSS)
  24,174   73,691   23,862   (29,112)
                 
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
  366   419   785   877 
             
                 
COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT
 $23,808  $73,272  $23,077  $(29,989)
             
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

11


THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
5

CONSOLIDATED BALANCE SHEETS
(Unaudited)
         
  June 30,  December 31, 
  2010  2009 
  (In thousands) 
ASSETS
        
         
CURRENT ASSETS:
        
Cash and cash equivalents $245  $86,230 
Receivables-        
Customers (less accumulated provisions of $4,809,000 and $5,239,000, respectively, for uncollectible accounts)  198,970   209,335 
Associated companies  73,008   98,954 
Other  10,377   11,661 
Notes receivable from associated companies  24,480   26,802 
Prepayments and other  4,390   9,973 
       
   311,470   442,955 
       
UTILITY PLANT:
        
In service  2,350,804   2,310,074 
Less — Accumulated provision for depreciation  911,368   888,169 
       
   1,439,436   1,421,905 
Construction work in progress  30,665   36,907 
       
   1,470,101   1,458,812 
       
OTHER PROPERTY AND INVESTMENTS:
        
Investment in lessor notes  340,033   388,641 
Other  10,108   10,220 
       
   350,141   398,861 
       
DEFERRED CHARGES AND OTHER ASSETS:
        
Goodwill  1,688,521   1,688,521 
Regulatory assets  468,119   545,505 
Pension assets (Note 5)     13,380 
Property taxes  77,319   77,319 
Other  12,912   12,777 
       
   2,246,872   2,337,502 
       
  $4,378,584  $4,638,130 
       
LIABILITIES AND CAPITALIZATION
        
         
CURRENT LIABILITIES:
        
Currently payable long-term debt $137  $117 
Short-term borrowings-        
Associated companies  224,031   339,728 
Accounts payable-        
Associated companies  35,605   68,634 
Other  15,707   17,166 
Accrued taxes  77,051   90,511 
Accrued interest  18,557   18,466 
Other  49,897   45,440 
       
   420,985   580,062 
       
CAPITALIZATION:
        
Common stockholders’ equity-        
Common stock, without par value, authorized 105,000,000 shares, 67,930,743 shares outstanding  884,878   884,897 
Accumulated other comprehensive loss  (150,214)  (138,158)
Retained earnings  532,380   597,248 
       
Total common stockholders’ equity  1,267,044   1,343,987 
Noncontrolling interest  18,017   20,592 
       
Total equity  1,285,061   1,364,579 
Long-term debt and other long-term obligations  1,852,488   1,872,750 
       
   3,137,549   3,237,329 
       
NONCURRENT LIABILITIES:
        
Accumulated deferred income taxes  632,696   644,745 
Accumulated deferred investment tax credits  11,415   11,836 
Retirement benefits  81,872   69,733 
Other  94,067   94,425 
       
   820,050   820,739 
       
COMMITMENTS AND CONTINGENCIES (Note 8)
        
  $4,378,584  $4,638,130 
       


The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

12


THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
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.        
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
         
  Six Months Ended 
  June 30 
  2010  2009 
  (In thousands) 
CASH FLOWS FROM OPERATING ACTIVITIES:
        
Net Income (Loss) $35,918  $(57,676)
Adjustments to reconcile net income (loss) to net cash from operating activities-        
Provision for depreciation  36,447   36,132 
Amortization of regulatory assets, net  75,946   286,317 
Deferral of new regulatory assets     (134,587)
Purchased power cost recovery reconciliation     2,072 
Deferred income taxes and investment tax credits, net  (18,083)  (58,506)
Accrued compensation and retirement benefits  5,421   2,092 
Accrued regulatory obligations  (444)  12,057 
Electric service prepayment programs     (3,510)
Cash collateral from suppliers  685   5,365 
Decrease (increase) in operating assets-        
Receivables  51,757   (84,469)
Prepayments and other current assets  5,392   (1,145)
Increase (decrease) in operating liabilities-        
Accounts payable  (34,488)  18,991 
Accrued taxes  (11,317)  (29,434)
Accrued interest  91   232 
Other  1,932   3,265 
       
Net cash provided from (used for) operating activities  149,257   (2,804)
       
         
CASH FLOWS FROM FINANCING ACTIVITIES:
        
New Financing-        
Short-term borrowings, net     47,423 
Redemptions and Repayments-        
Long-term debt  (54)  (368)
Short-term borrowings, net  (136,013)   
Common stock dividend payments  (100,000)  (25,000)
Other  (3,367)  (3,019)
       
Net cash provided from (used for) financing activities  (239,434)  19,036 
       
         
CASH FLOWS FROM INVESTING ACTIVITIES:
        
Property additions  (44,373)  (46,434)
Loan repayments from (loans to) associated companies, net  2,322   (5,449)
Redemptions of lessor notes  48,608   37,070 
Other  (2,365)  (1,415)
       
Net cash provided from (used for) investing activities  4,192   (16,228)
       
         
Net change in cash and cash equivalents  (85,985)  4 
Cash and cash equivalents at beginning of period  86,230   226 
       
Cash and cash equivalents at end of period $245  $230 
       
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

13


THE TOLEDO EDISON COMPANY
6

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                 
  Three Months Ended  Six Months Ended 
  June 30  June 30 
  2010  2009  2010  2009 
  (In thousands) 
STATEMENTS OF INCOME
                
                 
REVENUES:
                
Electric sales $114,691  $219,911  $240,122  $456,996 
Excise tax collections  6,059   6,297   13,100   14,026 
             
Total revenues  120,750   226,208   253,222   471,022 
             
                 
EXPENSES:
                
Purchased power from affiliates  38,654   130,564   85,654   255,888 
Purchased power from non-affiliates  23,675   18,244   49,784   58,781 
Other operating expenses  25,499   35,480   51,044   80,484 
Provision for depreciation  8,013   7,717   15,963   15,289 
Amortization (deferral) of regulatory assets, net  (1,800)  11,771   (10,299)  21,668 
General taxes  12,282   12,349   25,743   26,599 
             
Total expenses  106,323   216,125   217,889   458,709 
             
                 
OPERATING INCOME
  14,427   10,083   35,333   12,313 
             
                 
OTHER INCOME (EXPENSE):
                
Investment income  5,057   7,529   8,857   13,013 
Miscellaneous income (expense)  (945)  1,375   (2,351)  35 
Interest expense  (10,455)  (9,262)  (20,942)  (14,795)
Capitalized interest  80   50   158   92 
             
Total other expense  (6,263)  (308)  (14,278)  (1,655)
             
                 
INCOME BEFORE INCOME TAXES
  8,164   9,775   21,055   10,658 
                 
INCOME TAXES
  948   3,370   6,330   3,261 
             
                 
NET INCOME
  7,216   6,405   14,725   7,397 
             
                 
Noncontrolling interest income  2   1   5   3 
             
                 
EARNINGS AVAILABLE TO PARENT
 $7,214  $6,404  $14,720  $7,394 
             
                 
STATEMENTS OF COMPREHENSIVE INCOME
                
                 
NET INCOME
 $7,216  $6,405  $14,725  $7,397 
             
                 
OTHER COMPREHENSIVE INCOME (LOSS):
                
Pension and other postretirement benefits  714   19,016   1,010   19,149 
Change in unrealized gain on available-for-sale securities  (330)  (2,739)  39   (3,548)
             
Other comprehensive income  384   16,277   1,049   15,601 
Income tax expense related to other comprehensive income  65   7,224   235   7,205 
             
Other comprehensive income, net of tax  319   9,053   814   8,396 
             
                 
COMPREHENSIVE INCOME
  7,535   15,458   15,539   15,793 
                 
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST
  2   1   5   3 
             
                 
COMPREHENSIVE INCOME AVAILABLE TO PARENT
 $7,533  $15,457  $15,534  $15,790 
             


The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

14


THE TOLEDO EDISON COMPANY
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.        
CONSOLIDATED BALANCE SHEETS
(Unaudited)
         
  June 30,  December 31, 
  2010  2009 
  (In thousands) 
ASSETS
        
         
CURRENT ASSETS:
        
Cash and cash equivalents $77,843  $436,712 
Receivables-        
Customers  128   75 
Associated companies  52,068   90,191 
Other (less accumulated provisions of $298,000 and $208,000, respectively, for uncollectible accounts)  18,866   20,180 
Notes receivable from associated companies  95,919   85,101 
Prepayments and other  3,503   7,111 
       
   248,327   639,370 
       
UTILITY PLANT:
        
In service  932,788   912,930 
Less — Accumulated provision for depreciation  437,327   427,376 
       
   495,461   485,554 
Construction work in progress  7,906   9,069 
       
   503,367   494,623 
       
OTHER PROPERTY AND INVESTMENTS:
        
Investment in lessor notes  103,872   124,357 
Nuclear plant decommissioning trusts  75,540   73,935 
Other  1,539   1,580 
       
   180,951   199,872 
       
DEFERRED CHARGES AND OTHER ASSETS:
        
Goodwill  500,576   500,576 
Regulatory assets  81,799   69,557 
Property taxes  23,658   23,658 
Other  38,655   55,622 
       
   644,688   649,413 
       
  $1,577,333  $1,983,278 
       
LIABILITIES AND CAPITALIZATION
        
         
CURRENT LIABILITIES:
        
Currently payable long-term debt $216  $222 
Accounts payable-        
Associated companies  16,535   78,341 
Other  6,972   8,312 
Notes payable to associated companies     225,975 
Accrued taxes  20,069   25,734 
Lease market valuation liability  36,900   36,900 
Other  22,244   29,273 
       
   102,936   404,757 
       
CAPITALIZATION:
        
Common stockholders’ equity-        
Common stock, $5 par value, authorized 60,000,000 shares, 29,402,054 shares outstanding  147,010   147,010 
Other paid-in-capital  178,136   178,181 
Accumulated other comprehensive loss  (48,989)  (49,803)
Retained earnings  99,210   214,490 
       
Total common stockholders’ equity  375,367   489,878 
Noncontrolling interest  2,590   2,696 
       
Total equity  377,957   492,574 
Long-term debt and other long-term obligations  600,463   600,443 
       
   978,420   1,093,017 
       
NONCURRENT LIABILITIES:
        
Accumulated deferred income taxes  112,670   80,508 
Accumulated deferred investment tax credits  6,148   6,367 
Retirement benefits  67,507   65,988 
Asset retirement obligations  27,819   32,290 
Lease market valuation liability  217,750   236,200 
Other  64,083   64,151 
       
   495,977   485,504 
       
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 8)
        
  $1,577,333  $1,983,278 
       
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

15


THE TOLEDO EDISON COMPANY
7

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
         
  Six Months Ended 
  June 30 
  2010  2009 
  (In thousands) 
CASH FLOWS FROM OPERATING ACTIVITIES:
        
Net Income $14,725  $7,397 
Adjustments to reconcile net income to net cash from operating activities-        
Provision for depreciation  15,963   15,289 
Amortization (deferral) of regulatory assets, net  (10,299)  21,668 
Purchased power cost recovery reconciliation  60   (4,197)
Deferred rents and lease market valuation liability  (42,264)  (40,697)
Deferred income taxes and investment tax credits, net  16,503   (1,206)
Accrued compensation and retirement benefits  2,600   711 
Accrued regulatory obligations  (632)  4,450 
Electric service prepayment programs     (1,458)
Cash collateral from suppliers  343   2,755 
Decrease (increase) in operating assets-        
Receivables  52,754   1,075 
Prepayments and other current assets  3,608   (220)
Increase (decrease) in operating liabilities-        
Accounts payable  (61,195)  5,533 
Accrued taxes  (4,007)  (2,936)
Accrued interest     3,983 
Other  (9,020)  1,788 
       
Net cash provided from (used for) operating activities  (20,861)  13,935 
       
         
CASH FLOWS FROM FINANCING ACTIVITIES:
        
New Financing-        
Long-term debt     297,422 
Short-term borrowings, net     59,938 
Redemptions and Repayments-        
Long-term debt  (111)  (236)
Short-term borrowings, net  (225,975)   
Common stock dividend payments  (130,000)  (25,000)
Other  (112)  (247)
       
Net cash provided from (used for) financing activities  (356,198)  331,877 
       
         
CASH FLOWS FROM INVESTING ACTIVITIES:
        
Property additions  (20,237)  (21,661)
Leasehold improvement payments from associated companies  32,829    
Loans to associated companies, net  (10,818)  (19,819)
Redemptions of lessor notes  20,485   18,330 
Sales of investment securities held in trusts  106,814   77,323 
Purchases of investment securities held in trusts  (107,978)  (78,700)
Other  (2,905)  (1,845)
       
Net cash provided from (used for) investing activities  18,190   (26,372)
       
         
Net change in cash and cash equivalents  (358,869)  319,440 
Cash and cash equivalents at beginning of period  436,712   14 
       
Cash and cash equivalents at end of period $77,843  $319,454 
       


The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

16


JERSEY CENTRAL POWER & LIGHT COMPANY
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.                
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

                 
  Three Months Ended  Six Months Ended 
  June 30  June 30 
  2010  2009  2010  2009 
      (In thousands)     
REVENUES:
                
Electric sales $709,606  $697,061  $1,400,998  $1,457,981 
Excise tax collections  11,012   11,031   23,364   23,762 
             
Total revenues  720,618   708,092   1,424,362   1,481,743 
             
                 
EXPENSES:
                
Purchased power  410,470   423,950   824,486   905,191 
Other operating expenses  75,177   70,876   170,837   156,746 
Provision for depreciation  27,093   25,301   55,064   50,404 
Amortization of regulatory assets, net  81,326   80,018   150,774   166,849 
General taxes  14,902   12,587   31,338   30,083 
             
Total expenses  608,968   612,732   1,232,499   1,309,273 
             
                 
OPERATING INCOME
  111,650   95,360   191,863   172,470 
             
                 
OTHER INCOME (EXPENSE):
                
Miscellaneous income  1,649   2,007   3,482   2,812 
Interest expense  (30,041)  (29,671)  (59,464)  (57,539)
Capitalized interest  156   218   289   280 
             
Total other expense  (28,236)  (27,446)  (55,693)  (54,447)
             
                 
INCOME BEFORE INCOME TAXES
  83,414   67,914   136,170   118,023 
                 
INCOME TAXES
  33,521   29,848   57,051   52,399 
             
                 
NET INCOME
  49,893   38,066   79,119   65,624 
             
                 
OTHER COMPREHENSIVE INCOME:
                
Pension and other postretirement benefits  4,135   20,918   20,063   25,039 
Unrealized gain on derivative hedges  69   69   138   138 
             
Other comprehensive income  4,204   20,987   20,201   25,177 
Income tax expense related to other comprehensive income  1,441   11,059   7,999   12,489 
             
Other comprehensive income, net of tax  2,763   9,928   12,202   12,688 
             
                 
TOTAL COMPREHENSIVE INCOME
 $52,656  $47,994  $91,321  $78,312 
             
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

17


JERSEY CENTRAL POWER & LIGHT COMPANY
8

CONSOLIDATED BALANCE SHEETS
(Unaudited)
         
  June 30,  December 31, 
  2010  2009 
  (In thousands) 
ASSETS
        
CURRENT ASSETS:
        
Cash and cash equivalents $99  $27 
Receivables-        
Customers (less accumulated provisions of $3,362,000 and $3,506,000, respectively, for uncollectible accounts)  345,136   300,991 
Associated companies  11,778   12,884 
Other  25,626   21,877 
Notes receivable — associated companies  17,883   102,932 
Prepaid taxes  146,898   34,930 
Other  11,357   12,945 
       
   558,777   486,586 
       
         
UTILITY PLANT:
        
In service  4,524,706   4,463,490 
Less — Accumulated provision for depreciation  1,651,304   1,617,639 
       
   2,873,402   2,845,851 
Construction work in progress  55,825   54,251 
       
   2,929,227   2,900,102 
       
         
OTHER PROPERTY AND INVESTMENTS:
        
Nuclear plant decommissioning trusts  166,148   166,768 
Nuclear fuel disposal trust  204,088   199,677 
Other  2,209   2,149 
       
   372,445   368,594 
       
         
DEFERRED CHARGES AND OTHER ASSETS:
        
Goodwill  1,810,936   1,810,936 
Regulatory assets  800,898   888,143 
Other  29,849   27,096 
       
   2,641,683   2,726,175 
       
  $6,502,132  $6,481,457 
       
         
LIABILITIES AND CAPITALIZATION
        
CURRENT LIABILITIES:
        
Currently payable long-term debt $31,508  $30,639 
Short-term borrowings-        
Associated companies  57,850    
Accounts payable-        
Associated companies  15,158   26,882 
Other  202,049   168,093 
Accrued taxes  1,786   12,594 
Accrued interest  18,189   18,256 
Other  82,524   111,156 
       
   409,064   367,620 
       
         
CAPITALIZATION:
        
Common stockholders’ equity-        
Common stock, $10 par value, authorized 16,000,000 shares, 13,628,447 shares outstanding  136,284   136,284 
Other paid-in capital  2,507,003   2,507,049 
Accumulated other comprehensive loss  (230,810)  (243,012)
Retained earnings  189,194   200,075 
       
Total common stockholders’ equity  2,601,671   2,600,396 
Long-term debt and other long-term obligations  1,787,235   1,801,589 
       
   4,388,906   4,401,985 
       
         
NONCURRENT LIABILITIES:
        
Accumulated deferred income taxes  705,219   687,545 
Nuclear fuel disposal costs  196,623   196,511 
Retirement benefits  132,565   150,603 
Asset retirement obligations  104,878   101,568 
Power purchase contract liability  378,448   399,105 
Other  186,429   176,520 
       
   1,704,162   1,711,852 
       
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 8)
        
  $6,502,132  $6,481,457 
       


The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

18


JERSEY CENTRAL POWER & LIGHT COMPANY
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.        
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

         
  Six Months Ended 
  June 30 
  2010  2009 
  (In thousands) 
CASH FLOWS FROM OPERATING ACTIVITIES:
        
Net Income $79,119  $65,624 
Adjustments to reconcile net income to net cash from operating activities-        
Provision for depreciation  55,064   50,404 
Amortization of regulatory assets, net  150,774   166,849 
Deferred purchased power and other costs  (67,664)  (50,542)
Deferred income taxes and investment tax credits, net  (1,425)  3,440 
Accrued compensation and retirement benefits  2,608   (2,883)
Cash collateral paid, net  (23,400)  (209)
Decrease (increase) in operating assets-        
Receivables  (46,788)  41,228 
Prepayments and other current assets  (112,155)  (145,740)
Increase (decrease) in operating liabilities-        
Accounts payable  11,924   (19,321)
Accrued taxes  10,368   (14,007)
Accrued interest  (67)  9,373 
Tax collections payable     (9,714)
Other  (6,192)  4,555 
       
Net cash provided from operating activities  52,166   99,057 
       
         
CASH FLOWS FROM FINANCING ACTIVITIES:
        
New Financing-        
Long-term debt     299,619 
Short-term borrowings, net  57,850    
Redemptions and Repayments-        
Common stock     (150,000)
Long-term debt  (13,830)  (13,093)
Short-term borrowings, net     (56,267)
Common stock dividend payments  (90,000)  (88,000)
Other     (2,260)
       
Net cash used for financing activities  (45,980)  (10,001)
       
         
CASH FLOWS FROM INVESTING ACTIVITIES:
        
Property additions  (80,727)  (78,401)
Loan repayments from (loans to) associated companies, net  85,049   (1,341)
Sales of investment securities held in trusts  281,242   244,880 
Purchases of investment securities held in trusts  (289,454)  (252,856)
Other  (2,224)  (1,266)
       
Net cash used for investing activities  (6,114)  (88,984)
       
         
Net change in cash and cash equivalents  72   72 
Cash and cash equivalents at beginning of period  27   66 
       
Cash and cash equivalents at end of period $99  $138 
       
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

19


METROPOLITAN EDISON COMPANY
9

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                 
  Three Months Ended  Six Months Ended 
  June 30  June 30 
  2010  2009  2010  2009 
      (In thousands)     
REVENUES:
                
Electric sales $422,030  $360,022  $873,590  $769,708 
Gross receipts tax collections  20,629   17,586   42,196   37,569 
             
Total revenues  442,659   377,608   915,786   807,277 
             
                 
EXPENSES:
                
Purchased power from affiliates  149,000   78,652   310,080   178,729 
Purchased power from non-affiliates  85,276   123,299   177,204   247,210 
Other operating expenses  90,151   51,309   192,134   157,666 
Provision for depreciation  13,440   12,919   26,198   25,058 
Amortization of regulatory assets, net  48,589   61,548   97,389   89,139 
General taxes  19,894   22,034   41,634   43,969 
             
Total expenses  406,350   349,761   844,639   741,771 
             
                 
OPERATING INCOME
  36,309   27,847   71,147   65,506 
             
                 
OTHER INCOME (EXPENSE):
                
Interest income  880   2,769   2,097   5,955 
Miscellaneous income  1,381   1,058   3,554   1,914 
Interest expense  (13,002)  (14,763)  (26,775)  (28,122)
Capitalized interest  159   62   285   77 
             
Total other expense  (10,582)  (10,874)  (20,839)  (20,176)
             
                 
INCOME BEFORE INCOME TAXES
  25,727   16,973   50,308   45,330 
                 
INCOME TAXES
  8,618   6,968   20,884   18,703 
             
                 
NET INCOME
  17,109   10,005   29,424   26,627 
             
                 
OTHER COMPREHENSIVE INCOME:
                
Pension and other postretirement benefits  2,162   27,369   11,871   31,922 
Unrealized gain on derivative hedges  84   84   168   168 
             
Other comprehensive income  2,246   27,453   12,039   32,090 
Income tax expense related to other comprehensive income  724   13,592   4,901   15,385 
             
Other comprehensive income, net of tax  1,522   13,861   7,138   16,705 
             
                 
TOTAL COMPREHENSIVE INCOME
 $18,631  $23,866  $36,562  $43,332 
             
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

20


METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
         
  June 30,  December 31, 
  2010  2009 
  (In thousands) 
ASSETS
        
CURRENT ASSETS:
        
Cash and cash equivalents $126  $120 
Receivables-        
Customers (less accumulated provisions of $3,877,000 and $4,044,000, respectively, for uncollectible accounts)  188,771   171,052 
Associated companies  45,551   29,413 
Other  13,221   11,650 
Notes receivable from associated companies  11,207   97,150 
Prepaid taxes  46,475   15,229 
Other  649   1,459 
       
   306,000   326,073 
       
UTILITY PLANT:
        
In service  2,196,713   2,162,815 
Less — Accumulated provision for depreciation  830,042   810,746 
       
   1,366,671   1,352,069 
Construction work in progress  30,214   14,901 
       
   1,396,885   1,366,970 
       
OTHER PROPERTY AND INVESTMENTS:
        
Nuclear plant decommissioning trusts  263,752   266,479 
Other  881   890 
       
   264,633   267,369 
       
DEFERRED CHARGES AND OTHER ASSETS:
        
Goodwill  416,499   416,499 
Regulatory assets  385,392   356,754 
Power purchase contract asset  120,436   176,111 
Other  42,546   36,544 
       
   964,873   985,908 
       
  $2,932,391  $2,946,320 
       
         
LIABILITIES AND CAPITALIZATION
        
CURRENT LIABILITIES:
        
Currently payable long-term debt $28,500  $128,500 
Short-term borrowings-        
Associated companies  17,898    
Accounts payable-        
Associated companies  51,308   40,521 
Other  30,997   41,050 
Accrued taxes  20,689   11,170 
Accrued interest  16,085   17,362 
Other  28,588   24,520 
       
   194,065   263,123 
       
CAPITALIZATION:
        
Common stockholders’ equity-        
Common stock, without par value, authorized 900,000 shares, 859,500 shares outstanding  1,197,014   1,197,070 
Accumulated other comprehensive loss  (136,413)  (143,551)
Retained earnings  33,824   4,399 
       
Total common stockholders’ equity  1,094,425   1,057,918 
Long-term debt and other long-term obligations  713,920   713,873 
       
   1,808,345   1,771,791 
       
NONCURRENT LIABILITIES:
        
Accumulated deferred income taxes  454,777   453,462 
Accumulated deferred investment tax credits  7,090   7,313 
Nuclear fuel disposal costs  44,416   44,391 
Retirement benefits  29,194   33,605 
Asset retirement obligations  186,373   180,297 
Power purchase contract liability  158,987   143,135 
Other  49,144   49,203 
       
   929,981   911,406 
       
COMMITMENTS AND CONTINGENCIES (Note 8)
        
  $2,932,391  $2,946,320 
       
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

21


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.        
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

         
  Six Months Ended 
  June 30 
  2010  2009 
  (In thousands) 
CASH FLOWS FROM OPERATING ACTIVITIES:
        
Net Income $29,424  $26,627 
Adjustments to reconcile net income to net cash from operating activities-        
Provision for depreciation  26,198   25,058 
Amortization of regulatory assets, net  97,389   89,139 
Deferral of regulatory assets  (38,358)  (47,592)
Deferred income taxes and investment tax credits, net  (12,079)  30,135 
Accrued compensation and retirement benefits  (1,573)  3,250 
Cash collateral received (paid), net  50   (6,800)
Decrease (increase) in operating assets-        
Receivables  (29,439)  346 
Prepayments and other current assets  (30,436)  (39,068)
Increase (decrease) in operating liabilities-        
Accounts payable  733   (18,624)
Accrued taxes  9,519   (1,754)
Accrued interest  (1,277)  10,230 
Other  6,743   7,870 
       
Net cash provided from operating activities  56,894   78,817 
       
         
CASH FLOWS FROM FINANCING ACTIVITIES:
        
New Financing-        
Long-term debt     300,000 
Short-term borrowings, net  17,898    
Redemptions and Repayments-        
Long-term debt  (100,000)   
Short-term borrowings, net     (15,003)
Other     (2,267)
       
Net cash provided from (used for) financing activities  (82,102)  282,730 
       
         
CASH FLOWS FROM INVESTING ACTIVITIES:
        
Property additions  (54,405)  (48,464)
Sales of investment securities held in trusts  376,610   63,086 
Purchases of investment securities held in trusts  (381,219)  (67,668)
Loans from (to) associated companies, net  85,943   (306,448)
Other  (1,715)  (2,072)
       
Net cash provided from (used for) investing activities  25,214   (361,566)
       
         
Net change in cash and cash equivalents  6   (19)
Cash and cash equivalents at beginning of period  120   144 
       
Cash and cash equivalents at end of period $126  $125 
       
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

22


PENNSYLVANIA ELECTRIC COMPANY
10

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
                 
  Three Months Ended  Six Months Ended 
  June 30  June 30 
  2010  2009  2010  2009 
      (In thousands)     
REVENUES:
                
Electric sales $350,335  $316,881  $736,271  $688,174 
Gross receipts tax collections  16,162   14,804   33,686   32,096 
             
Total revenues  366,497   331,685   769,957   720,270 
             
                 
EXPENSES:
                
Purchased power from affiliates  152,945   72,166   321,345   168,247 
Purchased power from non-affiliates  86,829   125,317   178,252   252,483 
Other operating expenses  67,070   46,301   139,464   123,590 
Provision for depreciation  16,605   15,581   31,287   30,036 
Amortization (deferral) of regulatory assets, net  (10,522)  18,113   (20,488)  26,889 
General taxes  18,647   18,251   35,181   38,844 
             
Total expenses  331,574   295,729   685,041   640,089 
             
                 
OPERATING INCOME
  34,923   35,956   84,916   80,181 
             
                 
OTHER INCOME (EXPENSE):
                
Miscellaneous income  1,310   911   2,923   1,709 
Interest expense  (17,630)  (11,843)  (34,920)  (25,076)
Capitalized interest  183   29   323   51 
             
Total other expense  (16,137)  (10,903)  (31,674)  (23,316)
             
                 
INCOME BEFORE INCOME TAXES
  18,786   25,053   53,242   56,865 
                 
INCOME TAXES
  5,812   10,232   22,969   23,354 
             
                 
NET INCOME
  12,974   14,821   30,273   33,511 
             
                 
OTHER COMPREHENSIVE INCOME:
                
Pension and other postretirement benefits  1,830   29,400   10,377   32,355 
Unrealized gain on derivative hedges  16   16   32   32 
Change in unrealized gain on available-for-sale securities     6      (16)
             
Other comprehensive income  1,846   29,422   10,409   32,371 
Income tax expense related to other comprehensive income  483   15,100   3,767   16,155 
             
Other comprehensive income, net of tax  1,363   14,322   6,642   16,216 
             
                 
TOTAL COMPREHENSIVE INCOME
 $14,337  $29,143  $36,915  $49,727 
             
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

23




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.                
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)

         
  June 30,  December 31, 
  2010  2009 
  (In thousands) 
ASSETS
        
CURRENT ASSETS:
        
Cash and cash equivalents $10  $14 
Receivables-        
Customers (less accumulated provisions of $3,428,000 and $3,483,000, respectively, for uncollectible accounts)  137,450   139,302 
Associated companies  88,612   77,338 
Other  10,934   18,320 
Notes receivable from associated companies  14,092   14,589 
Prepaid taxes  56,450   18,946 
Other  758   1,400 
       
   308,306   269,909 
       
UTILITY PLANT:
        
In service  2,481,942   2,431,737 
Less — Accumulated provision for depreciation  918,963   901,990 
       
   1,562,979   1,529,747 
Construction work in progress  22,319   24,205 
       
   1,585,298   1,553,952 
       
OTHER PROPERTY AND INVESTMENTS:
        
Nuclear plant decommissioning trusts  140,611   142,603 
Non-utility generation trusts  96,988   120,070 
Other  283   289 
       
   237,882   262,962 
       
DEFERRED CHARGES AND OTHER ASSETS:
        
Goodwill  768,628   768,628 
Regulatory assets  138,557   9,045 
Power purchase contract asset  6,031   15,362 
Other  20,245   19,143 
       
   933,461   812,178 
       
  $3,064,947  $2,899,001 
       
LIABILITIES AND CAPITALIZATION
        
CURRENT LIABILITIES:
        
Currently payable long-term debt $69,310  $69,310 
Short-term borrowings-        
Associated companies  66,786   41,473 
Accounts payable-        
Associated companies  48,876   39,884 
Other  28,460   41,990 
Accrued taxes  5,071   6,409 
Accrued interest  17,625   17,598 
Other  24,696   22,741 
       
   260,824   239,405 
       
CAPITALIZATION:
        
Common stockholders’ equity-        
Common stock, $20 par value, authorized 5,400,000 shares, 4,427,577 shares outstanding  88,552   88,552 
Other paid-in capital  913,460   913,437 
Accumulated other comprehensive loss  (155,462)  (162,104)
Retained earnings  121,774   91,501 
       
Total common stockholders’ equity  968,324   931,386 
Long-term debt and other long-term obligations  1,072,199   1,072,181 
       
   2,040,523   2,003,567 
       
NONCURRENT LIABILITIES:
        
Accumulated deferred income taxes  296,829   242,040 
Retirement benefits  167,288   174,306 
Asset retirement obligations  94,933   91,841 
Power purchase contract liability  153,603   100,849 
Other  50,947   46,993 
       
   763,600   656,029 
       
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 8)
        
  $3,064,947  $2,899,001 
       
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

24


PENNSYLVANIA ELECTRIC COMPANY
11

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


         
  Six Months Ended 
  June 30 
  2010  2009 
  (In thousands) 
CASH FLOWS FROM OPERATING ACTIVITIES:
        
Net Income $30,273  $33,511 
Adjustments to reconcile net income to net cash from operating activities-        
Provision for depreciation  31,287   30,036 
Amortization (deferral) of regulatory assets, net  (20,488)  26,889 
Deferred costs recoverable as regulatory assets  (38,955)  (46,349)
Deferred income taxes and investment tax credits, net  42,943   24,700 
Accrued compensation and retirement benefits  4,216   490 
Cash collateral  (3,613)  2 
Decrease (increase) in operating assets-        
Receivables  3,266   42,494 
Prepayments and other current assets  (36,864)  (35,750)
Increase (decrease) in operating liabilities-        
Accounts payable  (4,603)  (10,108)
Accrued taxes  (1,339)  (7,629)
Accrued interest  28   (1,669)
Other  9,559   2,302 
       
Net cash provided from operating activities  15,710   58,919 
       
         
CASH FLOWS FROM FINANCING ACTIVITIES:
        
New Financing-        
Short-term borrowings, net  25,313   146,654 
Redemptions and Repayments-        
Long-term debt     (100,000)
Common stock dividend payments     (35,000)
Other  5    
       
Net cash provided from financing activities  25,318   11,654 
       
         
CASH FLOWS FROM INVESTING ACTIVITIES:
        
Property additions  (58,293)  (59,606)
Loans from associated companies, net  498   63 
Sales of investment securities held in trusts  133,934   53,504 
Purchases of investment securities held in trusts  (113,067)  (60,378)
Other  (4,104)  (4,168)
       
Net cash used for investing activities  (41,032)  (70,585)
       
         
Net change in cash and cash equivalents  (4)  (12)
Cash and cash equivalents at beginning of period  14   23 
       
Cash and cash equivalents at end of period $10  $11 
       
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.

25


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 THE 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, 20082009 for FirstEnergy, FES and the Utilities.Utilities, as applicable. 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 bethat it is the VIE's primary beneficiary.beneficiary (see Note 6). Investments in non-consolidated affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but are not control (20-50% owned companies, joint venturesthe primary beneficiary and partnerships)do not exercise control, 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'sentity’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 areis 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  Six Months 
Reconciliation of Basic and Diluted Earnings per Share Ended June 30  Ended June 30 
of Common Stock 2010  2009  2010  2009 
  (In millions, except per share amounts) 
                 
Earnings available to FirstEnergy Corp. $265  $414  $420  $533 
             
                 
Weighted average number of basic shares outstanding  304   304   304   304 
Assumed exercise of dilutive stock options and awards  1   1   1   2 
             
Weighted average number of diluted shares outstanding  305   305   305   306 
             
                 
Basic earnings per share of common stock $0.87  $1.36  $1.38  $1.75 
             
Diluted earnings per share of common stock $0.87  $1.36  $1.37  $1.75 
             
  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




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

(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“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 SeptemberJune 30, 20092010 and December 31, 2008:2009:

                
 
September 30, 2009
 
December 31, 2008
  June 30, 2010 December 31, 2009 
 Carrying Fair Carrying Fair  Carrying Fair Carrying Fair 
 
Value
 
Value
 
Value
 
Value
  Value Value Value Value 
 (In millions)  (In millions) 
FirstEnergy
 
$
13,675 
$
14,483 
$
11,585
 
$
11,146
  $13,346 $14,992 $13,753 $14,502 
FES
 4,233 4,304 
2,552
 
2,528
  3,932 4,386 4,224 4,306 
OE
 1,169 1,318 
1,232
 
1,223
  1,166 1,378 1,169 1,299 
CEI
 1,900 2,033 
1,741
 
1,618
  1,853 2,110 1,873 2,032 
TE
 600 656 
300
 
244
  600 682 600 638 
JCP&L
 1,849 1,977 
1,569
 
1,520
  1,826 2,013 1,840 1,950 
Met-Ed
 842 911 
542
 
519
  742 840 842 909 
Penelec
 1,179 1,221 
779
 
721
  1,144 1,233 1,144 1,177 
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

(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 held in available-for-sale securitiesnuclear decommissioning trusts, nuclear fuel disposal trusts and NUG trusts as of SeptemberJune 30, 20092010 and December 31, 2008:2009:

                                 
  June 30, 2010(1)  December 31, 2009(2) 
  Cost  Unrealized  Unrealized  Fair  Cost  Unrealized  Unrealized  Fair 
  Basis  Gains  Losses  Value  Basis  Gains  Losses  Value 
  (In millions) 
Debt securities
                                
FirstEnergy $1,404  $40  $  $1,444  $1,727  $22  $  $1,749 
FES  702   18      720   1,043   3      1,046 
OE  119   1      120   55         55 
TE  14         14   72         72 
JCP&L  278   11      289   271   9      280 
Met-Ed  130   5      135   120   5      125 
Penelec  161   5      166   166   5      171 
                                 
Equity securities
                                
FirstEnergy $250  $24  $  $274  $252  $43  $  $295 
JCP&L  74   4      78   74   11      85 
Met-Ed  117   14      131   117   23      140 
Penelec  59   6      65   61   9      70 
(1)Excludes cash balances: FirstEnergy — $463 million; FES — $388 million; OE — $6 million; TE — $61 million; JCP&L — $3 million; Met-Ed — $(2) million and Penelec - $7 million.
(2)Excludes cash balances: FirstEnergy — $137 million; FES — $43 million; OE - $66 million; TE — $2 million; JCP&L — $3 million and Penelec — $23 million.

27


  
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-monthsix-month period ended SeptemberJune 30, 2010 and 2009 were as follows:

                             
June 30, 2010 FirstEnergy  FES  OE  TE  JCP&L  Met-Ed  Penelec 
          (In millions)             
Proceeds from sales $1,916  $957  $60  $107  $281  $377  $134 
Realized gains  83   54   2   3   9   9   6 
Realized losses  86   58         9   12   7 
Interest and dividend income  37   22   1   1   7   3   3 
 FirstEnergy FES OE TE JCP&L Met-Ed Penelec                             
June 30, 2009June 30, 2009 FirstEnergy FES OE TE JCP&L Met-Ed Penelec 
 (In millions)  (In millions) 
Proceeds from sales
 $3,040 $2,153 $207 $171 $339 $89 $81  $1,001 $537  $25  $77 $245  $63  $54 
Realized gains
  186 162 11 7 4 1 1  30 24      
Realized losses
  96 62 3 - 11 13 7  91 58 3  11 12   
Interest and dividend income
  47 22 4 2 10 5 4  30  14 2     

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 foras of June 30, 2010 and December 31, 2009 (excluding emission allowances, employee benefits, cost method investments and equity method investments of $271$251 million and $293$264 million, respectively, that are not required to be disclosed) as of September 30, 2009 and December 31, 2008::

                                 
  June 30, 2010  December 31, 2009 
  Cost  Unrealized  Unrealized  Fair  Cost  Unrealized  Unrealized  Fair 
  Basis  Gains  Losses  Value  Basis  Gains  Losses  Value 
  (In millions) 
Debt Securities
                                
FirstEnergy $487  $93  $  $580  $544  $72  $  $616 
OE  205   55      260   217   29      246 
CEI  340   38      378   389   43      432 
  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



Notes Receivable
The following table provides the approximate fair value and related carrying amounts of notes receivable as of SeptemberJune 30, 20092010 and December 31, 2008:2009:

 
September 30, 2009
 
December 31, 2008
                 
 Carrying Fair Carrying Fair  June 30, 2010 December 31, 2009 
 
Value
 
Value
 
Value
 
Value
  Carrying Fair Carrying Fair 
Notes receivable (In millions) 
 Value Value Value Value 
 (In millions) 
Notes Receivable
 
FirstEnergy $45 $42 $45 $44  $36 $34 $36 $35 
FES 4 4 75 74    2 1 
OE 193 234 257 294 
TE
 161 180 
180
 
189
  104 117 124 141 
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.
(C) RECURRING FAIR VALUE MEASUREMENTS
Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between willing market participants on the measurement date. A fair value hierarchy has been established that prioritizes the inputs used to measure fair value. The maturity dates range from 2009hierarchy gives the highest priority to 2040.

(C)RECURRING FAIR VALUE MEASUREMENTS

FirstEnergy's valuation techniques, includingunadjusted quoted market prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy are disclosedas follows:
Level 1 — Quoted prices are available in Note 5active markets for identical assets or liabilities as of the Notes to Consolidated Financial Statements in FirstEnergy's Annual Report on Form 10-Kreporting date. Active markets are those where transactions for the year ended December 31, 2008.asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. FirstEnergy’s Level 1 assets and liabilities primarily consist of exchange-traded derivatives and equity securities listed on active exchanges that are held in various trusts.

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

28


Level 3 — Pricing inputs include inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. FirstEnergy develops its view of the future market price of key commodities through a combination of market observation and assessment (generally for the short term) and fundamental modeling (generally for the long term). Key fundamental electricity model inputs are generally directly observable in the market or derived from publicly available historic and forecast data. Some key inputs reflect forecasts published by industry leading consultants who generally employ similar fundamental modeling approaches. Fundamental model inputs and results, as well as the selection of consultants, reflect the consensus of appropriate FirstEnergy management. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. FirstEnergy’s Level 3 instruments consist exclusively of NUG contracts.
FirstEnergy utilizes market data and assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs.
The following tables set forth financial assets and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of SeptemberJune 30, 20092010 and December 31, 2008.2009. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. FirstEnergy'sFirstEnergy’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 June 30, 2010 
          Level 1          
  FirstEnergy  FES  OE  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Assets
                            
Nuclear Decommissioning Trust Investments
                            
Equity securities — consumer products $122  $  $  $  $35  $58  $29 
Equity securities — technology  51            15   24   12 
Equity securities — utilities & energy  52            15   25   12 
Equity securities — financial  42            12   20   10 
Equity securities — other  8            2   4   2 
                      
Total Assets(1)
 $275  $  $  $  $79  $131  $65 
                      
                             
Liabilities
                            
Derivatives — commodity contracts $5  $5  $  $  $  $  $ 
                      
Total Liabilities
 $5  $5  $  $  $  $  $ 
                      

29


                             
  Level 2 
  FirstEnergy  FES  OE  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Assets
                            
Nuclear Decommissioning Trust Investments
                            
U.S. government debt securities $538  $265  $121  $14  $36  $92  $10 
U.S. state debt securities  94            31   2   61 
Foreign government debt securities  297   297                
Corporate debt securities  225   158         20   42   5 
Other  458   388   5   62   1   1   1 
                      
Total nuclear decommissioning trust investments
 $1,612  $1,108  $126  $76  $88  $137  $77 
                      
                             
Rabbi Trust Investments
                            
Equity securities — financial $1  $  $  $  $  $  $ 
Other  12      1             
                      
Total rabbi trust investments
 $13  $  $1  $  $  $  $ 
                      
                             
Nuclear Fuel Disposal Trust Investments
                            
U.S. state debt securities $196  $  $  $  $196  $  $ 
Other  8            8       
                      
Total nuclear fuel disposal trust investments
 $204  $  $  $  $204  $  $ 
                      
                             
NUG Trust Investments
                            
U.S. state debt securities $97  $  $  $  $  $  $97 
                      
Total NUG trust investments
 $97  $  $  $  $  $  $97 
                      
                             
Derivatives
                            
Commodity contracts $111  $102  $  $  $2  $5  $2 
Interest rate contracts  62                   
                      
Total derivatives contracts
 $173  $102  $  $  $2  $5  $2 
                      
Total Assets(1)
 $2,099  $1,210  $127  $76  $294  $142  $176 
                      
                             
Liabilities
                            
Derivatives
                            
Commodity contracts $273  $273  $  $  $  $  $ 
                      
Total Liabilities
 $273  $273  $  $  $  $  $ 
                      
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
                             
  Level 3 
  FirstEnergy  FES  OE  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Assets
                            
Derivatives — NUG contracts(2)
 $134  $  $  $  $7  $121  $6 
                      
                             
Liabilities
                            
Derivatives — NUG contracts(2)
 $691  $  $  $  $378  $159  $154 
                      

 (1)
Consists of investments in nuclear decommissioning trusts, spent nuclear fuel trusts and NUG trusts. Balance excludes $2
(1)Excludes $(7) million of receivables, payables
and accrued income.
(2)NUG contracts are subject to regulatory accounting and do not impact earnings.

30


                             
  Recurring Fair Value Measures as of December 31, 2009 
  Level 1 
  FirstEnergy  FES  OE  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Assets
                            
Nuclear Decommissioning Trust Investments
                            
Equity securities — consumer products $130  $  $  $  $38  $59  $33 
Equity securities — technology  57            17   26   14 
Equity securities — utilities & energy  59            17   27   15 
Equity securities — financial  39            12   17   10 
Equity securities — other  9            3   4   2 
            ��         
Total Assets(1)
 $294  $  $  $  $87  $133  $74 
                      
                             
Liabilities
                            
Derivatives — commodity contracts $11  $11  $  $  $  $  $ 
                      
Total Liabilities
 $11  $11  $  $  $  $  $ 
                      

31


                             
  Level 2 
  FirstEnergy  FES  OE  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Assets
                            
Nuclear Decommissioning Trust Investments
                            
U.S. government debt securities $558  $306  $118  $72  $23  $30  $9 
U.S. state debt securities  188   15         41   82   50 
Foreign government debt securities  279   279                
Corporate debt securities  484   443         15   20   6 
Other  35   29   2      1   2   1 
                      
Total nuclear decommissioning trust investments
 $1,544  $1,072  $120  $72  $80  $134  $66 
                      
                             
Rabbi Trust Investments
                            
Equity securities — financial $1  $  $  $  $  $  $ 
Other  9                   
                      
Total rabbi trust investments
 $10  $  $  $  $  $  $ 
                      
                             
Nuclear Fuel Disposal Trust Investments
                            
U.S. state debt securities $189  $  $  $  $189  $  $ 
Other  11            11       
                      
Total nuclear fuel disposal trust investments
 $200  $  $  $  $200  $  $ 
��                     
                             
NUG Trust Investments
                            
U.S. state debt securities $101  $  $  $  $  $  $101 
Other  19                  19 
                      
Total NUG trust investments
 $120  $  $  $  $  $  $120 
                      
                             
Derivatives — Commodity Contracts
 $34  $15  $  $  $5  $9  $5 
                             
Other
 $1  $  $  $  $  $  $ 
                      
Total Assets(1)
 $1,909  $1,087  $120  $72  $285  $143  $191 
                      
                             
Liabilities
                            
Derivatives — commodity contracts $224  $224  $  $  $  $  $ 
                      
Total Liabilities
 $224  $224  $  $  $  $  $ 
                      
(2)     NUG contracts are completely offset by regulatory assets and do not impact earnings.
                             
  Level 3 
  FirstEnergy  FES  OE  TE  JCP&L  Met-Ed  Penelec 
  (In millions) 
Assets
                            
Derivatives — NUG contracts(2)
 $200  $  $  $  $9  $176  $15 
                      
                             
Liabilities
                            
Derivatives — NUG contracts(2)
 $643  $  $  $  $399  $143  $101 
                      

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
(1)Excludes $21 million of receivables, payables
and accrued income.

(2)NUG contracts are subject to regulatory accounting and do not impact earnings.
(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.

32



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 ninesix months ended SeptemberJune 30, 20092010 and 20082009 (in millions):

                 
  FirstEnergy  JCP&L  Met-Ed  Penelec 
Balance as of January 1, 2010 $(444) $(391) $33  $(86)
Settlements(1)
  146   70   36   40 
Unrealized losses(1)
  (259)  (50)  (107)  (102)
             
Balance as of June 30, 2010 $(557) $(371) $(38) $(148)
             
                 
Balance as of April 1, 2010 $(590) $(394) $(30) $(166)
Settlements(1)
  68   30   19   19 
Unrealized losses(1)
  (35)  (7)  (27)  (1)
             
Balance as of June 30, 2010 $(557) $(371) $(38) $(148)
             
  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)
 
                 
  FirstEnergy  JCP&L  Met-Ed  Penelec 
Balance as of January 1, 2009 $(332) $(518) $150  $36 
Settlements(1)
  179   90   43   47 
Unrealized losses(1)
  (383)  (38)  (170)  (176)
             
Balance as of June 30, 2009 $(536) $(466) $23  $(93)
             
                 
Balance as of April 1, 2009 $(476) $(518) $76  $(34)
Settlements(1)
  96   44   26   27 
Unrealized gains (losses)(1)
  (156)  8   (79)  (86)
             
Balance as of June 30, 2009 $(536) $(466) $23  $(93)
             
(1)Changes in fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.

 (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.

5.4. 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'sFirstEnergy’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 purchasepurchases and normal sales criteria. Derivatives that meet those criteria are accounted for at cost.cost under the accrual method of accounting. The changes in the fair value of derivative instruments that do not meet the normal purchasepurchases and normal sales criteria are included in purchased power, other expense, unrealized gain (loss) on derivative hedges in other comprehensive income (loss), or as part of the value of the hedged item. Based on derivative contracts held as of June 30, 2010, an adverse 10% change in commodity prices would decrease net income by approximately $9 million ($6 million net of tax) during the next twelve months. A hypothetical 10% increase in the interest rates associated with variable-rate debt would decrease net income by less than $1 million for the three and six months ended June 30, 2010.

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.Cash Flow 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 useshas used forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives arewere 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 SeptemberJune 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:2010, no forward starting swap agreements were outstanding.

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   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 cash flow hedges totaled $94$109 million ($5771 million net of tax) as of SeptemberJune 30, 2009.2010. Based on current estimates, approximately $11 million will be amortized to interest expense during the next twelve months. FirstEnergy’sThe table below provides the activity of AOCL related to interest rate cash flow hedges as of June 30, 2010 and 2009.

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  Three Months Ended  Six Months Ended 
  June 30  June 30 
  2010  2009  2010  2009 
  (In millions)  (In millions) 
Effective Portion                
Gain Recognized in AOCL $  $2  $  $ 
Reclassification from AOCL into Interest Expense  (3)  (6)  (6)  (11)

Fair Value Hedges
FirstEnergy uses fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues, protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. In May of 2010, FirstEnergy terminated fixed-for-floating interest rate swap agreements with a notional value of $3.15 billion, which resulted in cash proceeds of $43.1 million. These proceeds will generally be amortized to earnings over the life of the underlying debt.
Effective June 1, 2010, FirstEnergy executed multiple fixed-for-floating interest rate swap agreements with a combined notional value of $3.2 billion, which essentially replaced the swap agreements terminated in May of 2010. As of June 30, 2010, the debt underlying the $3.2 billion outstanding notional amount of interest rate swaps dohad a weighted average fixed interest rate of 6%, which the swaps have converted to a current weighted average variable rate of 4%.
On July 16, 2010, FirstEnergy terminated these fixed-for-floating interest rate swap agreements with a notional value of $3.2 billion, which resulted in cash proceeds of $83.6 million. These proceeds will be amortized to earnings over the life of the underlying debt. While FirstEnergy currently does not includehave any contingent credit risk related features.interest rate swaps outstanding, costs associated with entering into future swap transactions may be increased as a result of the recent passage of the Dodd-Frank Wall Street Reform and Consumer Protection Act, which requires increased regulation of swaps, swap dealers and major swap participants.

The following tables summarize the fair value of interest rate swaps in FirstEnergy’s Consolidated Balance Sheets:
                   
Derivative Assets  Derivative Liabilities 
  Fair Value    Fair Value 
  June 30,  December 31,    June 30,  December 31, 
  2010  2009    2010  2009 
  (In millions)    (In millions) 
Fair Value Hedges         Fair Value Hedges        
Interest Rate Swaps $62  $  Interest Rate Swaps $  $ 
               
Noncurrent Assets $62  $  Noncurrent Liabilities $  $ 
               

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 whichwhere 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.

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

                   
Derivative Assets  Derivative Liabilities 
  Fair Value    Fair Value 
  June 30,  December 31,    June 30,  December 31, 
  2010  2009    2010  2009 
  (In millions)    (In millions) 
Cash Flow Hedges         Cash Flow Hedges        
Electricity Forwards         Electricity Forwards        
Current Assets $40  $3  Current Liabilities $50  $7 
NonCurrent Assets  57   11  NonCurrent Liabilities  54   12 
Natural Gas Futures         Natural Gas Futures        
Current Assets       Current Liabilities  4   9 
NonCurrent Assets       NonCurrent Liabilities      
Other         Other        
Current Assets       Current Liabilities  1   2 
NonCurrent Assets       NonCurrent Liabilities      
               
  $97  $14    $109  $30 
               
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 Liabilities5 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


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Derivative Assets  Derivative Liabilities 
  Fair Value    Fair Value 
  June 30,  December 31,    June 30,  December 31, 
  2010  2009    2010  2009 
  (In millions)    (In millions) 
Economic Hedges         Economic Hedges        
NUG Contracts         NUG Contracts        
Power Purchase         Power Purchase        
Contract Asset $134  $200  Contract Liability $691  $643 
Other         Other        
Current Assets  4     Current Liabilities  114   106 
NonCurrent Assets  10   19  NonCurrent Liabilities  55   97 
               
   148   219     860   846 
               
Total Commodity Derivatives $245  $233  Total Commodity Derivatives $969  $876 
               
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 SeptemberJune 30, 2009.2010:

                 
  Purchases  Sales  Net  Units 
      (In thousands)     
Electricity Forwards  21,596   (19,965)  1,631  MWH
Heating Oil Futures  2,100      2,100  Gallons
Natural Gas Futures  1,250   (1,000)  250  mmBtu

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 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 ninesix months ended SeptemberJune 30, 20092010 and 2008,2009, for instruments designated in cash flow hedging relationships and not in hedging relationships, respectively, are summarized in the following tables:

                 
  Three Months Ended June 30, 
  Electricity  Natural Gas  Heating Oil    
Derivatives in Cash Flow Hedging Relationships Forwards  Futures  Futures  Total 
  (In millions) 
2010
                
Gain (Loss) Recognized in AOCL (Effective Portion) $(8) $  $  $(8)
Effective Gain (Loss) Reclassified to: (1)
                
Purchased Power Expense  (7)        (7)
Fuel Expense     (3)  (1)  (4)
                 
2009
                
Gain (Loss) Recognized in AOCL (Effective Portion) $6  $  $2  $8 
Effective Gain (Loss) Reclassified to: (1)
                
Purchased Power Expense  1         1 
Fuel Expense     (4)  (4)  (8)
Derivatives in Cash Flow Hedging RelationshipsElectricity  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.
            
                 
  Six Months Ended June 30, 
  Electricity  Natural Gas  Heating Oil    
Derivatives in Cash Flow Hedging Relationships Forwards  Futures  Futures  Total 
  (In millions) 
2010
                
Gain (Loss) Recognized in AOCL (Effective Portion) $(13) $(1) $  $(14)
Effective Gain (Loss) Reclassified to: (1)
                
Purchased Power Expense  (11)        (11)
Fuel Expense     (6)  (2)  (8)
                 
2009
                
Gain (Loss) Recognized in AOCL (Effective Portion) $4  $(7) $1  $(2)
Effective Gain (Loss) Reclassified to: (1)
                
Purchased Power Expense  (17)        (17)
Fuel Expense     (4)  (8)  (12)
(1)The ineffective portion was immaterial.

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  Three Months Ended June 30, 
  NUG       
Derivatives Not in Hedging Relationships Contracts  Other  Total 
  (In millions) 
2010
            
Unrealized Gain (Loss) Recognized in:            
Purchased Power Expense $  $35  $35 
Regulatory Assets (2)
  (35)     (35)
          
  $(35) $35  $ 
          
             
Realized Gain (Loss) Reclassified to:            
Purchased Power Expense $  $(31) $(31)
Regulatory Assets (2)
  (68)     (68)
          
  $(68) $(31) $(99)
          
             
2009
            
Unrealized Gain (Loss) Recognized in:            
Fuel Expense (1)
 $   2  $2 
Regulatory Assets (2)
  (156) $   (156)
          
  $(156) $2  $(154)
          
             
Realized Gain (Loss) Reclassified to:            
Fuel Expense (1)
 $  $  $ 
Regulatory Assets (2)
  (96)     (96)
          
  $(96) $  $(96)
          

             
  Six Months Ended June 30, 
  NUG       
Derivatives Not in Hedging Relationships Contracts  Other  Total 
  (In millions) 
2010
            
Unrealized Gain (Loss) Recognized in:            
Purchased Power Expense $  $(17) $(17)
Regulatory Assets (2)
  (259)     (259)
          
  $(259) $(17) $(276)
          
             
Realized Gain (Loss) Reclassified to:            
Purchased Power Expense $  $(56) $(56)
Regulatory Assets (2)
  (146)  9   (137)
          
  $(146) $(47) $(193)
          
             
2009
            
Unrealized Gain (Loss) Recognized in:            
Fuel Expense (1)
 $  $2  $2 
Regulatory Assets (2)
  (383)     (383)
          
   (383) $2  $(381)
          
Realized Gain (Loss) Reclassified to:            
Fuel Expense (1)
 $  $(1) $(1)
Regulatory Assets (2)
  (179)  10   (169)
          
  $(179) $9  $(170)
          
(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.
  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. 


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Total unamortized losses included in AOCL associated with commodity derivatives were $9$11 million ($57 million net of tax) as of SeptemberJune 30, 2009,2010, as compared to $44$15 million ($279 million net of tax) as of December 31, 2008.2009. The net of tax change resulted from a net $7$10 million decreaseincrease related to current hedging activity and a $15$12 million decrease due to net hedge losses reclassified to earnings during the first ninesix months of 2009.2010. Based on current estimates, approximately $3$10 million (after(net of tax) of the net deferred losses on derivative instruments in AOCL as of SeptemberJune 30, 20092010 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.

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Many of FirstEnergy’s commodity derivatives contain credit risk features. As of SeptemberJune 30, 2009,2010, FirstEnergy posted $133$194 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 SeptemberJune 30, 20092010 was $2$177 million, for which $106$194 million in collateral has been posted. If FirstEnergy’s credit rating were to fall below investment grade, it would be required to post $18$37 million of additional collateral related to commodity derivatives.

6.5. 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)expense for the three months ended SeptemberJune 30, 2010 and 2009 was $21 million and 2008 were $36 million (including $9 million attributable to the VERO-related charge mentioned above), and $(15)$38 million, respectively. For the nine months ended September 30, 2009 and 2008, FirstEnergy’s net pension and OPEB expenses (benefits) were $117expense for the six months ended June 30, 2010 and 2009 was $45 million and $(44)$80 million, respectively. The components of FirstEnergy'sFirstEnergy’s net pension and other postretirement benefit costs (including amounts capitalized) for the three months and ninesix months ended September 30,June, 2010 and 2009, and 2008, consisted of the following:

                 
  Three Months Ended  Six Months Ended 
  June 30  June 30 
Pension Benefits 2010  2009  2010  2009 
      (In millions)     
Service cost $25  $22  $49  $43 
Interest cost  79   80   157   159 
Expected return on plan assets  (90)  (81)  (181)  (162)
Amortization of prior service cost  3   3   6   7 
Recognized net actuarial loss  47   42   94   85 
             
Net periodic cost $64  $66  $125  $132 
             
                 
  Three Months Ended  Six Months Ended 
  June 30  June 30 
Other Postretirement Benefits 2010  2009  2010  2009 
      (In millions)     
Service cost $3  $4  $5  $8 
Interest cost  11   18   22   38 
Expected return on plan assets  (9)  (9)  (18)  (18)
Amortization of prior service cost  (48)  (41)  (96)  (79)
Recognized net actuarial loss  15   15   30   31 
             
Net periodic cost $(28) $(13) $(57) $(20)
             

38


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 other postretirement benefit obligations are allocated to FirstEnergy'sFirstEnergy’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 other postretirement benefit costs (including amounts capitalized) recognized by FES and each of the UtilitiesFirstEnergy’s subsidiaries for the three months and ninesix months ended SeptemberJune 30, 20092010 and 20082009 were as follows:

                 
  Three Months Ended  Six Months Ended 
  June 30  June 30 
Pension Benefit Cost (Credit) 2010  2009  2010  2009 
      (In millions)     
FES $22  $18  $44  $36 
OE  6   7   11   14 
CEI  5   5   11   10 
TE  2   2   4   3 
JCP&L  6   9   12   18 
Met-Ed  3   6   5   11 
Penelec  5   4   9   9 
Other FirstEnergy Subsidiaries  15   15   29   31 
             
  $64  $66  $125  $132 
             
 Three Months Ended Nine Months Ended                 
 September 30 September 30  Three Months Ended Six Months Ended 
Pension Benefit Cost (Credit) 2009 2008 2009 2008 
 June 30 June 30 
Other Postretirement Benefit Cost (Credit) 2010 2009 2010 2009 
 (In millions)  (In millions) 
FES $19 $5 $56 $16  $(7) $(3) $(13) $(4)
OE  6  (6) 20  (18)  (6)  (3)  (12)  (5)
CEI  5  (1) 14  (3)  (1)   (3) 1 
TE  2  (1) 5  (2)    (1) 1 
JCP&L  8  (3) 26  (10)  (2)  (1)  (4)  (2)
Met-Ed  5  (2) 16  (7)  (2)  (1)  (4)  (2)
Penelec  4  (3) 13  (9)  (2)  (1)  (4)  (2)
Other FirstEnergy subsidiaries  15  (3) 46  (9)
Other FirstEnergy Subsidiaries  (8)  (4)  (16)  (7)
 $64 $(14)$196 $(42)         
 $(28) $(13) $(57) $(20)
         


  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)


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7.6. VARIABLE INTEREST ENTITIES

On January 1, 2010, FirstEnergy adopted the amendments to the consolidation topic addressing VIEs. This standard requires that FirstEnergy and its subsidiaries consolidate VIEs when they are determinedperform a qualitative analysis to determine whether a variable interest gives FirstEnergy or its subsidiaries a controlling financial interest in a VIE. This analysis identifies the primary beneficiary of a VIE as the enterprise that has both the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses of the entity that could potentially be significant to the VIE'sVIE or the right to receive benefits from the entity that could potentially be significant to the VIE. This standard also requires an ongoing reassessment of the primary beneficiary of a VIE and eliminates the quantitative approach previously required for determining whether an entity is the primary beneficiary. There was no impact to FirstEnergy or its subsidiaries as a result of the adoption of this standard.
FirstEnergy’s consolidated financial statements include the accounts of entities in which it has a controlling financial interest. 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 ($1415 million), the acquisition of additional interest in certain joint ventures ($13 million), and distributions to owners ($4 million). for the six months ended June 30, 2010.

Mining Operations

On July 16, 2008, FEV entered into aFirstEnergy consolidates certain VIEs in which it has financial control through disproportionate economics in its equity and debt investments in the entities. These VIEs include: FEV’s 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 inoperations; 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 VIEsbond trusts that were created in 1996 and 1997, respectively, to refinance debt originally issued in connection with sale and leaseback transactions. PNBVtransactions; and Shippingport financial data are includedwholly owned limited liability companies of JCP&L created to sell transition bonds to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station, of which $326 million was outstanding as of June 30, 2010.

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In order to evaluate contracts under the consolidation guidance, FirstEnergy aggregated contracts into two categories based on similar risk characteristics and significance as follows:
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 21 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 consolidated financial statementscreation of, OE and CEI, respectively.has no equity or debt invested in, these entities.

PNBV was established to purchase a portionFirstEnergy has determined that for all but two of the lease obligation bonds issued in connection with OE's 1987 sale and leaseback of itsthese entities, neither JCP&L, nor Met-Ed nor Penelec have variable interests in the Perry Plantentities or the entities are governmental or not-for-profit organizations not within the scope of consolidation consideration for VIEs. JCP&L may hold variable interests in the remaining two entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants. However, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.
Since JCP&L has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs it incurs for power. FirstEnergy expects any above-market costs it incurs to be recovered from customers. Purchased power costs related to the two contracts that may contain a variable interest were $53 million and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV$48 million for the purchasethree months ended June 30, 2010, and 2009, respectively and $117 million and $115 million for the six months ended June 30, 2010 and 2009, respectively.
Loss Contingencies
FirstEnergy has variable interests in certain sale-leaseback transactions. FirstEnergy concluded that it is not the primary beneficiary 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 allthese interests as it does not have control over the significant activities affecting the economics 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

arrangement.
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'scompany’s net exposure to loss based upon the casualty value provisions mentioned above:

             
  Maximum  Discounted Lease  Net 
  Exposure  Payments, net(1)  Exposure 
  (In millions) 
FES $1,352  $1,165  $187 
OE  693   499   194 
CEI(2)
  662   70   592 
TE(2)
  662   339   323 
  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) 
(1)The net present value of FirstEnergy'sFirstEnergy’s consolidated sale and
leaseback operating lease commitments is $1.7 billion
$1.6 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.

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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.

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8.7. 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'scompany’s tax return. After reaching a settlement at appeals related primarily to the capitalization of certain costs for the tax years 2005-2008, as well as reaching a settlement on an unrelated state tax matter in the second quarter of 2010, FirstEnergy recognized approximately $70 million of net tax benefits, including $13 million that favorably affected FirstEnergy’s effective tax rate for the second quarter of 2010. The remaining portion of the tax benefit recognized in the first six months of 2010 increased FirstEnergy’s accumulated deferred income taxes for the settled temporary tax item. 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 majorityThere were no material changes to FirstEnergy’s unrecognized tax benefits in the second quarter of 2009.
As of June 30, 2010, it is reasonably possible that approximately $11 million 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 willmay be resolved within the next twelve months, of which approximately $148$11 million, if recognized, would affect FirstEnergy'sFirstEnergy’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 CompanyFirstEnergy 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 2008noted above favorably affected FirstEnergy’s effective tax rate by $12$11 million in the third quarter and first ninesix months of 2008.2010. During the first ninesix months of 2009, there were no material changes to the amount of interest accrued. The net amount of accumulated interest accrued as of SeptemberJune 30, 20092010 was $67million,$6 million, as compared to $59$21 million as of December 31, 2008.2009.

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In 2008,As a result of the Patient Protection and Affordable Care Act and the Health Care and Education Affordability Reconciliation Act signed into law on March 23, 2010 and March 30, 2010, respectively, beginning in 2013 the tax deduction available to FirstEnergy on behalf of FGCO and NGC, filed a change in accounting method relatedwill be reduced to the extent that drug costs are reimbursed under the Medicare Part D retiree subsidy program. As retiree healthcare liabilities and related tax impacts are already reflected in FirstEnergy’s consolidated financial statements, the change resulted in a charge to repair and maintain electric generation stations. DuringFirstEnergy’s earnings in the secondfirst quarter of 2009,2010 of approximately $13 million and a reduction in accumulated deferred tax assets associated with these subsidies. This change reflects the IRS approvedanticipated increase in income taxes that will occur as a result of 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.

law.
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 arewere under appeal. In the fourth quarter of 2009, these items were settled at appeals and sent to Joint Committee on Taxation for final review. The federal audits for the years 2004-2006 were completed in the third quarter of 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. In the second quarter of 2010, the items under appeal for tax years 2006 and 2007 were settled and sent to Joint Committee on Taxation for final review. The IRS began auditing the year 2008 in February 2008 and the audit was completed in July 2010 with one item under appeal. The 2009 tax year 2009audit began in February 2009 under its Compliance Assurance Process program.and the 2010 tax year began in February 2010. Neither audit is expected to close before December 2009.2010. 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'sFirstEnergy’s financial condition or results of operations.

9.8. 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 SeptemberJune 30, 2009,2010, outstanding guarantees and other assurances aggregated approximately $4.1$3.9 billion, consisting primarily of parental guarantees ($10.9 billion), subsidiaries’ guarantees ($2.62.5 billion), surety bonds ($0.1 billion) and LOCs ($0.40.5 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 legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties'counterparties’ claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy'sFirstEnergy’s guarantee enables the counterparty'scounterparty’s legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.4$0.3 billion (included in the $1$0.9 billion showndiscussed above) as of SeptemberJune 30, 20092010 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.

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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 ana LOC or accelerated payments may be required of the subsidiary. As of SeptemberJune 30, 2009, FirstEnergy's2010, FirstEnergy’s maximum exposure under these collateral provisions was $616$451 million, consisting of $53$37 million due to “material adverse event” contractual clauses, $83 million due to an acceleration of payment or funding obligation, and $563$331 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$609 million, consisting of $60$56 million due to “material adverse event” contractual clauses, $83 million related to an acceleration of payment or funding obligation, and $639$470 million due to a below investment grade credit rating.

Most of FirstEnergy'sFirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $103$90 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.

41



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’ contractspower portfolio as of SeptemberJune 30, 2009,2010, and forward prices as of that date, FES had $183 millionhas posted collateral of outstanding collateral payments of which $134 million is included in other assets on the Consolidated Balance Sheet as of September 30, 2009.$245 million. Under a hypothetical adverse change in forward prices (15% decrease(95% confidence level change in the first 12 months and 20% decrease inforward prices thereafter)over a one year time horizon), FES would be required to post an additional $45$107 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 thean amount of approximatelyup to $500 million. The surplus margin guarantySurplus 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 toand FES 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 FirstEnergyCompliance with regard to environmental mattersregulations could have a material adverse effect on FirstEnergy'sFirstEnergy’s earnings and competitive position to the extent that itFirstEnergy 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.

CAA Compliance
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 and NOX emissions regulations.regulations under the CAA. FirstEnergy complies with SO2 and NOx reduction requirements under the CAA and State Implementation Plan(s) under the CAA (SIPs) by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower-emitting plants, and/or using emission allowances. 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.penalties.

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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 are operated under a consent decree with the EPA and DOJ that requires reductions of NOX and SO2 emissions through the installation of pollution control devices or repoweringrepowering. OE and provides forPenn are subject to 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,combustion, are currently estimated to be $706approximately $399 million for 2009-2012 (with $414 million expected to be spent in 2009).2010-2012.

On May 22,In 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing ofPennFuture filed 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,limitations, in the United StatesU.S. District Court for the Western District of Pennsylvania. In July 2008, three additional complaints were filed against FGCO in the United StatesU.S. District Court for the Western District of Pennsylvania also seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, twoTwo of the threethese complaints also 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, aA 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 dismissedPennFuture. FGCO believes 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 claimsremaining plaintiffs 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 statestates of New Jersey and Connecticut filed a CAA citizen suitsuits in 2007 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 Jerseythese suits allege that "modifications"“modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR or permitting under the CAA's prevention of significant deteriorationCAA’s PSD 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 ofIn September 2009, 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'sMet-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 statutepenalties. The parties dispute the scope of limitations grounds in orderMet-Ed’s indemnity obligation 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.and from Sithe Energy.


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OnIn January 14, 2009, the EPA issued a NOV to Reliant alleging new source reviewNSR 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, NOV1986 and also alleged new source reviewNSR violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. Met-Ed, 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.

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OnIn June 11, 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. alleging that "modifications"“modifications” at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or permitting under the CAA's preventionCAA’s PSD program. In May 2010, the EPA issued a second NOV to Mission Energy Westside, Inc., Penelec, NYSEG and others that have had an ownership interest in the Homer City Power Station containing in all material respects identical allegations as the June 2008 NOV. On July 20, 2010, the states of significant deterioration program.New York and Pennsylvania provided Mission Energy Westside, Inc., Penelec, NYSEG and others that have had an ownership interest in the Homer City Power Station a notification required 60 days prior to filing a citizen suit under the CAA. 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.under dispute and 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. OnIn August 12, 2009, the EPA issued a Finding of Violation and NOV alleging violations of the Clean Air ActCAA and Ohio regulations, including the prevention of significant deterioration (“PSD”), non-attainment new source review (NNSR”),PSD, 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 informationa request pursuant to Section 114(a) of the Clean Air Act requiring FirstEnergy to submitfor certain operating and maintenance information and planning information regarding the Eastlake, Lake Shore, Bay Shorefor these same generating plants 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. Later in 2009, FGCO received another information request regarding emission projections for the Eastlake generating plant. FGCO intends to comply with the CAA, including the 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.The EPA’s CAIR requires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, (2009/2010 for SO2and Phase II in 2015 for both NOX and SO2)2015), 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 inIn 2008, the United StatesU.S. 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. OnIn 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 StatesThe 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"“8-hour” ozone NAAQS. FGCO'sIn July 2010, the EPA proposed the Clean Air Transport Rule (CATR) to replace CAIR, which remains in effect until the EPA finalizes CATR. CATR requires reductions of NOX and SO2 emissions in two phases (2012 and 2014), ultimately capping SO2 emissions in affected states to 2.6 million tons annually and NOX emissions to 1.3 million tons annually. The EPA proposed a preferred regulatory approach that allows trading of NOX and SO2 emission allowances between power plants located in the same state with severe limits on interstate trading and two alternative approaches—the first eliminates interstate trading of NOX and SO2 emission allowances and the second eliminates trading of NOX and SO2 emission allowances in its entirety. Depending on the actions taken by the EPA with respect to CATR, the proposed MACT regulations discussed below, and any future regulations that are ultimately implemented, FGCO’s future cost of compliance with these regulations may be substantialsubstantial. Management is currently assessing the impact of these environmental proposals and will depend, in part,other factors on FGCO’s facilities, particularly on the action taken by the EPA in responseoperation of its smaller, non-supercritical units. For example, management may decide to the Court’s ruling.idle certain of these units or operate them on a seasonal basis until developments clarify.

Hazardous Air Pollutant Emissions

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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 theThe EPA’s CAMR which provides for a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping nationalnationwide emissions of mercury emissions at 38 tons by 2010 (as a "co-benefit"“co-benefit” from implementation of SO2 and NOX emission caps under the EPA'sEPA’s CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United StatesThe U.S. Court of Appeals for the District of Columbia. On February 8, 2008,Columbia, at the Courturging of several states and environmental groups 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 openedentered into a 30-day comment period on a proposed consent decree that would obligate the EPArequiring it 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 withOn April 29, 2010, the EPA issued proposed MACT regulations may be substantialrequiring emissions reductions of mercury and will dependother hazardous air pollutants from non-electric generating unit boilers, including boilers which do not use fossil fuels such as the proposed Burger biomass repowering project. If finalized, the non-electric generating unit MACT regulations could also provide precedent for MACT standards applicable to electric generating units. Depending on the action taken by the EPA and on how any future regulations are ultimately implemented.

implemented, FGCO’s future cost of compliance with MACT regulations may be substantial and changes to FGCO’s operations may result.
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,December 23, 2009, the Supreme Court of Pennsylvania affirmed the Commonwealth Court of Pennsylvania declaredruling that Pennsylvania’s mercury rule is “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule. It is anticipated that compliance with these regulations, if the Commonwealth Court’s rulings were reversed on appeal and Pennsylvania’s mercury rule was implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant (FirstEnergy’s only Pennsylvania coal-fired power plant) until 2015, if at all.

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Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing, 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. 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. 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 theThe 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 thoseelectric generating plants and other facilities. On April 17,In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that will require FirstEnergy to measure GHG emissions commencing in 2010 and submit reports commencing in 2011. In December 2009, the EPA released a “Proposed Endangermentits final “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 toGHG increase the threat of climate change. AlthoughIn April 2010, the EPA’s proposed finding, ifEPA finalized doesnew GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles and clarified that GHG regulation under the CAA will not establish emission requirementsbe triggered 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 supportand other stationary sources until January 2, 2011, at the establishment of future emission requirements byearliest. In May 2010, 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 programsCAA program would be required. The EPA is proposing a major sourceestablished an emissions applicability threshold of 25,00075,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) effective January 2, 2011 for existing facilities under the Title V operating permits program and theCAA’s Prevention of Significant Determination (PSD) portionprogram, but until July 1, 2011 that emissions applicability threshold will only apply if PSD is triggered by non-carbon dioxide pollutants.
At the international level, the Kyoto Protocol, signed by the U.S. in 1998 but never submitted for ratification by the U.S. Senate, was intended to address global warming by reducing the amount of NSR. EPA is also proposingman-made GHG, including CO2, emitted by developed countries by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a significance level between 10,000consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement which recognized the scientific view that the increase in global temperature should be below two degrees Celsius, included a commitment by developed countries to provide funds, approaching $30 billion over the next three years with a goal of increasing to $100 billion by 2020, and 25,000 tpy CO2eestablished the “Copenhagen Green Climate Fund” to determine if existing major sources making modifications that resultsupport mitigation, adaptation, and other climate-related activities in an increase ofdeveloping countries. Once they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia, and the United States, would commit to quantified economy-wide emissions above the significance leveltargets from 2020, while developing countries, including Brazil, China, and India, would be requiredagree to obtain a PSD permit.take mitigation actions, subject to their domestic measurement, reporting, and verification.


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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.grounds; however, a subsequent ruling from the U.S. Court of Appeals for the Fifth Circuit reinstated the lower court dismissal of a complaint alleging damage from GHG emissions. 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 eitherthis litigation, should the courtscourt of appeals decisionsdecision be affirmed or not subjected to further review, 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'sFirstEnergy’s plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FirstEnergy'sFirstEnergy’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, theThe 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'sfacility’s cooling water system). On January 26, 2007,The EPA has taken 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, notingposition 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

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cooling water intake structures. On April 1, 2009, the U.S. Supreme Court of the United States reversed one significant aspect of the Second Circuit Court’sCircuit’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 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.effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant’s water intake channel to divert fish away from the plant’s water intake system. On March 15, 2010, the EPA issued a draft permit for the Bay Shore power plant requiring installation of reverse louvers in its entire water intake channel by December 31, 2014. Depending on the results of such studies and the EPA’s further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

TheIn June 2008, the U.S. Attorney'sAttorney’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

AsFederal and state hazardous waste regulations have been promulgated 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.1976. Certain fossil-fuel combustion waste products,residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA'sEPA’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,residuals, including whether they should be regulated as hazardous or non-hazardous waste.
On December 30, 2009, in an advanced notice of public rulemaking, the EPA said that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. On May 4, 2010, the EPA proposed two options for additional regulation as non-hazardous waste orof coal combustion residuals, including the option of regulation as a hazardous waste. In March and June 2009,special waste under 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 aEPA’s 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 productsmanagement program which could have a significant impact on ourthe management, beneficial use and disposal of coal ash. FGCO'scombustion residuals. FGCO’s future cost of compliance with any coal combustion wasteresiduals 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 EPA or 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 SeptemberJune 30, 2009,2010, based on estimates of the total costs of cleanup, the Utilities'Utilities’ proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $104$105 million (JCP&L - - $77— $76 million, TE - $1 million, CEI - $1 million, FGCO - $1 million and FirstEnergy - $24— $26 million) have been accrued through SeptemberJune 30, 2009.2010. Included in the total are accrued liabilities of approximately $68$67 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&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'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)Early in 2010, the Appellate Division limited the class only to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, basedheard oral argument 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 theirplaintiff’s appeal of the trial court'scourt’s decision decertifying the class. Theclass, and on July 29, 2010, the Appellate Division upheld the trial court’s decision.
Litigation Relating to the Proposed Allegheny Energy Merger
In connection with the proposed merger (Note 15), purported shareholders of Allegheny Energy have filed putative shareholder class action and/or derivative lawsuits in Pennsylvania and Maryland state courts, as well as in the U.S. District Court for the Western District of Pennsylvania, against Allegheny Energy and its directors and certain officers, referred to as the Allegheny Energy defendants, FirstEnergy and Merger Sub. In summary, the lawsuits allege, among other things, that the Allegheny Energy directors breached their fiduciary duties by approving the merger

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agreement, and that Allegheny Energy, FirstEnergy and Merger Sub aided and abetted in these alleged breaches of fiduciary duty. The complaints seek, among other things, jury trials, money damages and injunctive relief. Additional details about the actions are provided below. While FirstEnergy believes the lawsuits are without merit and has scheduleddefended vigorously against the claims, in order to avoid the costs associated with the litigation, the defendants have agreed to the terms of a disclosure-based settlement of the lawsuits. The defendants reached an agreement with counsel for all of the plaintiffs concerning fee applications, but a formal stipulation of settlement has not yet been filed with any court. If the parties are unable to obtain final approval of the settlement, then litigation will proceed, and the outcome of any such litigation is inherently uncertain. If a dismissal is not granted or a settlement is not reached, these lawsuits could prevent or delay the completion of the merger and result in substantial costs to FirstEnergy. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger closes may adversely affect FirstEnergy’s business, financial condition or results of operations.
Four putative class action and derivative lawsuits were filed in the Circuit Court for Baltimore City, Maryland. One was withdrawn. The court consolidated the three cases under the captionOakmont Capital Management, LLC v. Evanson, et al., C.A. No. 24-C-10-1301, and appointed Lewis M. Lynn as Lead Plaintiff. Plaintiff Lynn filed a Consolidated Amended Complaint on April 12, 2010. On April 21, 2010, defendants filed Motions to Dismiss the Consolidated Amended Complaint for failure to state a claim. The court has stayed all discovery pending resolution of those motions. The court also has entered a stipulated order certifying a class with no opt-out rights. On May 27, 2010, the parties reported to the court that they have agreed to the terms of a disclosure-based settlement and requested that the court cancel the oral argument on the motions to dismiss that had been scheduled for JanuaryJune 3, 2010. On May 28, 2010, the court removed the hearing from its calendar.
Three shareholder lawsuits were filed in the Court of Common Pleas of Westmoreland County, Pennsylvania, raising putative class action and derivative claims against the Allegheny Energy directors and officers, FirstEnergy and Allegheny Energy. The court has consolidated these actions under the caption,In re Allegheny Energy, Inc. Shareholder Class and Derivative, Litigation, Lead Case No. 1101 of 2010, and appointed lead counsel. On April 5, 2010..2010, the Allegheny Energy defendants filed a Motion to Stay the Proceedings. Shortly thereafter, FirstEnergy similarly filed a Motion to Stay. Plaintiffs filed a Motion for Expedited Discovery. The court scheduled a hearing on the motions for May 27, 2010. On May 21, 2010, plaintiffs filed a Verified Consolidated Shareholder Derivative and Class Complaint. On May 26, 2010, the parties filed a Motion for a Continuance of the May 27 hearing, which the court granted. On June 1, 2010, the parties reported to the court that they have agreed to the terms of a disclosure-based settlement.

A putative shareholder lawsuit styled as a class action was filed in the U.S. District Court for the Western District of Pennsylvania and is captionedLouisiana Municipal Police Employees’ Retirement System v. Evanson, et al., C.A. No. 10-319 NBF. On June 1, 2010, the parties reported to the court that they have agreed to the terms of a disclosure-based settlement.
Nuclear Plant Matters

During a planned refueling outage that began on February 28, 2010, FENOC conducted a non destructive examination and testing of the Control Rod Drive Mechanism (CRDM) Nozzles of the Davis-Besse reactor pressure vessel head. FENOC identified flaws in CRDM nozzles that required modification. The NRC was notified of these findings, along with federal, state and local officials. On March 17, 2010, the NRC sent a special inspection team to Davis-Besse to assess the adequacy of FENOC’s identification, analyses and resolution of the CRDM nozzle flaws and to ensure acceptable modifications were made prior to placing the RPV head back in service. After successfully completing the modifications, FENOC committed to take a number of corrective actions including strengthening leakage monitoring procedures and shutting Davis-Besse down no later than October 1, 2011, to replace the reactor pressure vessel head with nozzles made of material less susceptible to primary water stress corrosion cracking further enhancing the safe and reliable operations of the plant. On June 29, 2010, FENOC returned Davis-Besse to service.
In August 2007, FENOC submitted an applicationOn April 5, 2010, the Union of Concerned Scientists (UCS) requested that the NRC issue a Show Cause Order, or otherwise delay the restart of the Davis-Besse Nuclear Power Station until the NRC determines that adequate protection standards have been met and reasonable assurance exists that these standards will continue to be met after the plant’s operation is resumed. By a letter dated July 13, 2010, the NRC denied UCS’s request for immediate action because “the NRC has conducted rigorous and independent assessments of returning the Davis-Besse reactor vessel head to service and its continued operation, and determined that it was safe for the plant to restart.” The UCS petition was referred to a petition manager for further review. What additional actions, if any that the NRC takes in response 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.

UCS request, have not been determined.
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of Septemberobligations. As of June 30, 2009,2010, 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 byBy a letter dated March 8, 2010, primarily as a result of the Beaver Valley Power Station operating license renewal, FENOC requested that the NRC FirstEnergy annually recalculates and adjusts the amount of itsreduce FirstEnergy’s parental guarantee as appropriate. The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based on market conditions. Ifto $15 million and notified the value ofstaff that it no longer planned to make the trusts decline byadditional contributions into the trusts. By a material amount, FirstEnergy’s obligationsletter dated July 14, 2010, the NRC stated that it had no objection to fund the trusts may increase. The recent disruptionreduction 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.guarantee.

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Other Legal Matters

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

On April 14, 2010, JCP&L's&L reached an agreement on a settlement package with its bargaining unit employees filedregarding a grievance challenging JCP&L's&L’s 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004,The agreement included an arbitration panel concluded thatagreed-upon settlement amount and extension of the call-out procedure violated the parties' collective bargaining agreement. On September 9, 2005,July 22, 2010, the arbitration panel issuedcourt signed an opinionorder approving and implementing the parties’ agreement. As of June 30, 2010, JCP&L reduced its reserve to award approximately $16$9 million for the settlement which will be paid to the employees over the next thirty days beginning on July 25, 2010. The collective bargaining unit employees. A final order identifyingagreement extension is also effective as of July 25, 2010.
On February 16, 2010, a class action lawsuit was filed in Geauga County Court of Common Pleas against FirstEnergy, CEI and OE seeking declaratory judgment and injunctive relief, as well as compensatory, incidental and consequential damages, on behalf of a class of customers related to the individual damage amountsreduction of a discount that had previously been in place for residential customers with electric heating, electric water heating, or load management systems. The reduction in the discount was issued on October 31, 2007 andapproved by the award appeal process was initiated. The unionPUCO. On March 18, 2010, the named-defendant companies filed a motion withto dismiss the federal Courtcase due to confirm the award and JCP&L filed its answer and counterclaim to vacatelack of jurisdiction of the awardcourt of common pleas. The court has not yet ruled 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’sthat motion to vacate the arbitration decision and granted the union’s motiondismiss. The named-defendant companies will continue 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.

defend these claims including challenging any class certification.
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'sFirstEnergy’s or its subsidiaries'subsidiaries’ financial condition, results of operations and cash flows.

10.9. REGULATORY MATTERS

(A) RELIABILITY INITIATIVES

In 2005, Congress amended the Federal Power Act to provide for federally-enforceable mandatory reliability standards. TheFederally-enforceable 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 responsibilitiesthese reliability standards to eight regional entities, including ReliabilityFirstCorporation. All of FirstEnergy’s facilities are located within the ReliabilityFirstregion. FirstEnergy actively participates in the NERC and ReliabilityFirststakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards.standards implemented and enforced by the ReliabilityFirstCorporation.

FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, it is clearFirstEnergy also believes that the NERC, ReliabilityFirstand 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, thetime; however, 2005 amendments to the Federal Power ActFPA 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 thusthat could 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 withresulting in customers in the affected area losing power. Power was restoredpower for up 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 requiredNERC has submitted first and second Requests for Information regarding this and another related matter. 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 interviewsis complying 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.these requests. JCP&L is not able at this time to predict what actions, if any, that the NERC may take basedwith respect to this matter.

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(B) OHIO
The Ohio Companies operate under an Amended ESP, which expires on the data submittals or interview results.

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On June 5, 2009, FirstEnergy self-reported to ReliabilityFirstMay 31, 2011, and provides for generation supplied through 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.CBP. 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,Amended ESP also allows 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 (Rider DSI) at an overall average rate of $.002$0.002 per KWH for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addressedOhio Companies currently purchase generation at the average wholesale rate of a number of other issues, including but not limited to, rate design for various customer classes, and resolutionCBP conducted in May 2009. FES is one of the prudence review and the collection of deferred costs that were approved in prior proceedings. On February 26, 2009,suppliers to the Ohio Companies filed a Supplemental Stipulation, which was signed or not opposed by virtually all ofthrough 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.CBP. 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,a $136.6 million distribution rate increase for the Ohio Companies filed applications within January 2009, which went into effect on January 23, 2009 for OE ($68.9 million) and TE ($38.5 million) and on May 1, 2009 for CEI ($29.2 million). As one element of the PUCO to recover three different categories of deferred distribution costs on an accelerated basis. In the Ohio Companies' Amended ESP, the Ohio Companies agreed not to seek an additional base distribution rate increase, subject to certain exceptions, that would be effective before January 1, 2012. Applications for rehearing of the PUCO approvedorder in 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 applicationsdistribution case were approvedfiled 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.party. The Ohio Companies askedraised numerous issues in their application for rehearing related to rate recovery of certain expenses, recovery of line extension costs, the Commission to issuelevel of rate of return and the amount of general plant balances. The PUCO has not yet issued a rulingsubstantive Entry on or before December 2, 2009.Rehearing.

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 establishthrough a CBP, to secure generation supply for customers who do not shop with an alternative supplier andfor the period beginning June 1, 2011. The CBP 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 reduceand supplier risk and encourage bidder participation. A technical conference wasand hearings were held on October 29,in 2009 atand the PUCO.matter has been fully briefed. Pursuant to SB221, the PUCO has 90 days from the date of the application to determine whether the MRO meets certain statutory requirements, therefore,requirements. Although the Ohio Companies have requested a PUCO determination by January 18, 2020.2010, on February 3, 2010, the PUCO announced that its determination would be delayed. Under a determination that such statutory requirements wereare met, and to the extent the ESP described below has not been implemented, the Ohio Companies would be ableexpect to implement the MRO.
On March 23, 2010, the Ohio Companies filed an application for a new ESP, which if approved by the PUCO, would go into effect on June 1, 2011 and conclude on May 31, 2014. Attached to the application was a Stipulation and Recommendation signed by the Ohio Companies, the Staff of the PUCO, and an additional fourteen parties signing as Signatory Parties, with two additional parties agreeing not to oppose the adoption of the Stipulation. The material terms of the Stipulation include a CBP similar to the one used in May 2009 and the one proposed in the October 2009 MRO filing; a 6% generation discount to certain low-income customers provided by the Ohio Companies through a bilateral wholesale contract with FES; no increase in base distribution rates through May 31, 2014; and a new distribution rider, Delivery Capital Recovery Rider (Rider DCR), to recover a return of, and on, capital investments in the delivery system. This Rider substitutes for Rider DSI which terminates by its own terms. The Ohio Companies also agree not to collect certain amounts associated with RTEP and administrative costs associated with the move to PJM. Many of the existing riders approved in the previous ESP remain in effect, some with modifications. The new ESP also requests the resolution of current proceedings pending at the PUCO regarding corporate separation, elements of the smart grid proceeding and the move to PJM. The evidentiary hearing began on April 20, 2010, at the PUCO. The Stipulation requested a decision by the PUCO by May 5, 2010. On April 28, 2010, the PUCO Chairman issued a statement that the PUCO would not issue a decision on May 5, 2010, and would take additional time to review the case record. FirstEnergy recorded approximately $39.5 million of regulatory asset impairments and expenses related to the ESP. On May 12, 2010 a supplemental stipulation was filed that added two additional parties to the Stipulation, namely the City of Akron, Ohio and Council for Smaller Enterprises, to provide additional energy efficiency benefits. Pursuant to a PUCO Entry, a hearing was held on June 21, 2010 to consider the estimated bill impacts arising from the proposed ESP, and testimony was provided in support of the supplemental stipulation. On July 22, 2010, a second supplemental stipulation was filed that, among other provisions and if approved, would provide a commitment that retail customers of the Ohio Companies will not pay certain costs related to the companies’ integration into PJM, a regional transmission organization, for the longer of the five year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals $360 million, and establishes a $12 million fund to assist low income customers over the term of the ESP. Additional parties signing or not opposing the second supplemental stipulation include Northeast Ohio Public Energy Council (NOPEC), Northwest Ohio Aggregation Coalition (NOAC), Environmental Law and Policy Center and a number of low income community agencies. A hearing was held on the second supplemental stipulation on July 29, 2010. The matter is awaiting decision from the PUCO.
Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will 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 0.75% reduction each year thereafter through 2018. The PUCO may amend these benchmarks in certain, limited circumstances, and the Ohio Companies filed an application with the PUCO seeking such amendments. On January 7, 2010, the PUCO amended the Ohio Companies’ 2009 energy efficiency benchmarks to zero, contingent upon the Ohio Companies meeting the revised benchmarks in a period of not more than three years. On March 10, 2010, the PUCO found that the Ohio Companies peak demand reduction programs complied with PUCO rules.

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On December 15, 2009, the Ohio Companies filed the required three year portfolio plan seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. On March 8, 2010, the Ohio Companies filed their 2009 Status Update Report with the PUCO in which they indicated compliance with the 2009 statutory energy efficiency and peak demand benchmarks as those benchmarks were amended as described above. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers. The Ohio Companies’ three year portfolio plan is still awaiting decision from the PUCO. The plan has yet to be approved by the PUCO, which is delaying the launch of the programs described in the plan. Without such approval, the Ohio Companies’ compliance with 2010 benchmarks is jeopardized and if not approved soon may require the Ohio Companies to seek an amendment to their annual benchmark requirements for 2010. Failure to comply with the benchmarks or to obtain such an amendment may subject the Companies to an assessment by the PUCO of a forfeiture.
Additionally under SB221, 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. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RFPs sought RECs, including solar RECs and RECs generated in Ohio in order to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2009, 2010 and 2011. The RECs acquired through these two RFPs will be used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. On March 10, 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market. The PUCO reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies’ acquired through their 2009 RFP processes, provided the Companies’ 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. On April 15, 2010, the Ohio Companies and FES (due to its status as an electric service company in Ohio) filed compliance reports with the PUCO setting forth how they individually satisfied the alternative energy requirements in SB221 for 2009. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark, which application is still pending. On July 1, 2010, the Ohio Companies announced their intent to conduct an RFP in 2010 to secure RECs and solar RECs needed to meet the CBP
Ohio Companies’ alternative energy requirements as set forth in SB221. RFP bids are due August 3, 2010 and contracts are expected to be signed the week of August 9, 2010.

On February 12, 2010, OE and CEI filed an application with the PUCO to establish a new credit for all-electric customers. On March 3, 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect on March 17, 2010. On April 15, 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that the new credit would remain in place through at least the 2011 winter season, and charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect on May 21, 2010. The Ohio Companies also filed on May 14, 2010 an application for rehearing of the Second Entry on Rehearing, which was granted for purposes of further consideration on June 9, 2010. No hearing has been scheduled in this matter.
As noted above in Note 8, FirstEnergy, CEI and OE filed a motion to dismiss a class action lawsuit related to the PUCO approved reduction of a discount that had previously been in place for residential customers with electric heating, electric water heating, or load management systems. The court has not yet ruled on that motion to dismiss.
(C) PENNSYLVANIA

Met-Ed and Penelec purchase a portion of their PLRPOLR 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 PLRPOLR 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 proposes129, with 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,August 12, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance filing tofiled a settlement agreement with 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 ingeneration procurement plan, reflecting the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero forsettlement on 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.but two reserved issues. On July 30,November 6, 2009, the PPUC entered an orderOrder approving the 5-year NUG Statement, approvingsettlement and finding in favor of Met-Ed and Penelec on the reductiontwo reserved issues. Generation procurement began in January 2010.
On February 8, 2010, Penn filed a Petition for Approval of its Default Service Plan for the CTC,period June 1, 2011 through May 31, 2013. The parties to the proceeding have reached a settlement on all issues and directingfiled a joint petition to approve the settlement agreement in July 2010. The PPUC is required to issue an order on the plan no later than November 8, 2010. If approved, procurement under the plan is expected to begin January 2011.

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The PPUC adopted a Motion on January 28, 2010 and subsequently entered an Order on March 3, 2010 which denies the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, and directs Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructs Met-Ed and Penelec to work with the various intervening parties to file a tariff supplement implementing this change.recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. On July 31, 2009,March 18, 2010, Met-Ed and Penelec filed a Petition with the PPUC requesting that it stay the portion of the March 3, 2010 Order requiring the filing of tariff supplements decreasingto end collection of marginal transmission loss costs. By Order entered March 25, 2010, the CTCPPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC’s order, Met-Ed and Penelec filed the plan to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges and the plan for the use of these funds to mitigate future generation rate in complianceincreases commencing January 1, 2011. The PPUC approved this plan June 7, 2010. On April 1, 2010, Met-Ed and Penelec filed a Petition for Review with the July 30, 2009 order,Commonwealth Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. Although the ultimate outcome of this matter cannot be determined at this time, it is the belief of Met-Ed and increasingPenelec that they should prevail in the appeal and therefore expect to fully recover the approximately $199.7 million ($158.5 million for Met-Ed and $41.2 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011. On April 2, 2010, Met-Ed and Penelec filed a Response to the PPUC’s March 3, 2010 Order requesting approval of procedures to establish separate accounts to track all marginal transmission loss revenues and related interest and the use of those funds to mitigate future generation rate in complianceincreases commencing January 1, 2011, and the PPUC entered an Order on June 7, 2010, granting Met-Ed’s and Penelec’s request. On July 9 2010, Met-Ed and Penelec filed their briefs with the companies’ Restructuring OrdersCommonwealth Court of 1998. Pennsylvania. The Office of Small Business Advocate filed its brief on July 9, 2010. The PPUC’s brief is due to be filed in August 2010.
On August 14, 2009,May 20, 2010, the PPUC issued Secretarial Letters approving Met-Edapproved Met-Ed’s and Penelec’s compliance filings. annual updates to their TSC rider for the period June 1, 2010 through December 31, 2010 including marginal transmission losses as approved by the PPUC, although the recovery of marginal losses will be subject to the outcome of the proceeding related to the 2008 TSC filing as described above. The TSC for Met-Ed’s customers increased to be fully recovered by December 31, 2010.
Act 129 was enacted in 2008 to address issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Among other things Act 129 required utilities to file with the PPUC an energy efficiency and peak load reduction plan, or EE&C Plan, by July 1, 2009, setting forth the utilities’ plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of 4.5% by May 31, 2013. The PPUC entered an Order on February 26, 2010 approving the Pennsylvania Companies’ EE&C Plans and the tariff rider with rates effective March 1, 2010.
Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation Plan with the PPUC. This plan proposes a 24-month assessment period in which the Pennsylvania Companies will assess their needs, select the necessary technology, secure vendors, train personnel, install and test support equipment, and establish a cost effective and strategic deployment schedule, which currently is expected to be completed in fifteen years. Met-Ed, Penelec and Penn estimate assessment period costs at approximately $29.5 million, which the Pennsylvania Companies, in their plan, proposed to recover through an automatic adjustment clause. The ALJ’s Initial Decision approved the Smart Meter Plan as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; eliminating the provision of interest in the 1307(e) reconciliation; providing for the recovery of reasonable and prudent costs minus resulting savings from installation and use of smart meters; and reflecting that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. On April 15, 2010, the PPUC adopted a Motion by Chairman Cawley that modified the ALJ’s initial decision, and decided various issues regarding the Smart Meter Implementation Plan for the Pennsylvania Companies. The PPUC entered its Order on June 9, 2010, consistent with the Chairman’s Motion. On June 24, 2010, Met-Ed, Penelec and Penn filed a Petition for Reconsideration of a single portion of the PPUC’s Order regarding the future ability to roll smart meter costs into base rates.
Legislation addressing rate mitigation and the expiration of rate caps was introduced in the legislative session that ended in 2008; several bills addressing these issues were introduced in the 2009 legislative session. The final form and impact of such legislation is uncertain.
By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30 day30-day comment period on whether “thethe 1998 Restructuring Settlement allows Met-Ed and Penelec to apply over-collection of NUG over collectioncosts 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 werevarious parties 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 Alliancecomments objecting to the above accounting method utilized by Met-Ed and Penelec. The Companies filed reply comments on October 26, 2009,Met-Ed and awaitPenelec are awaiting further action by the decision of the PPUC.PPUC.

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(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 SeptemberJune 30, 2009,2010, the accumulated deferred cost balance totaled approximately $102$81 million.

To better align the recovery of expected costs, on July 26, 2010, JCP&L filed a request to decrease the amount recovered for the costs incurred under the NUG agreements by $180 million annually. If approved as filed, the change would not go into effect until January 1, 2011.
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 2009.2009 estimated at $736 million (in 2003 dollars). 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 dueOn April 16, 2010, the NJBPU issued an order indefinitely suspending the requirement of New Jersey utilities to be filed withsubmit Utility Master Plans until such time as the BPU by July 1, 2010.status of the EMP has been made clear. At this time, FirstEnergy and JCP&L cannot determine the impact, if any, the EMP may have on their operations.

In support of theformer New Jersey Governor'sGovernor Corzine’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 BPUNJBPU on August 19, 2009, and implementation will beginbegan in 2009. Approval for the project related to energy efficiency programs intended to complement those currently being offered was denied by the NJBPU on December 1, 2009. On July 6, 2010, the January 30, 2009 petition directed to infrastructure investment which had been pending before the NJBPU was withdrawn by JCP&L. 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")(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.rate based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a load flow methodology, referred to as “DFAX”, generally referred to as a “beneficiary pays” basis.approach to allocating the cost of high voltage transmission facilities. The FERC found that PJM’s current beneficiary-pays cost allocation methodology iswas 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 FERC ultimately issued an order approving use of the beneficiary pays method of cost allocation for transmission facilities included in the PJM regional plan that operate below 500 kV.
The FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. On February 11, 2008, AEPorder was 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,Circuit, which issued a decision on behalf of its affiliated operating utility companies, filed a motion to intervene on March 10,August 6, 2009. The Seventh Circuit Courtcourt affirmed FERC’s ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new 500+ kV facilities on a load ratio share basis and, based on this finding, remanded the rate design issue back to FERC.

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In an order dated January 21, 2010, FERC set the matter for “paper hearings” — meaning that FERC called for parties to submit comments or written testimony pursuant to the schedule described in the order. FERC identified nine separate issues for comments, and directed PJM to file the first round of Appeals has held this appealcomments on February 22, 2010, with other parties submitting responsive comments within 45 days, and reply comments 30 days later. PJM filed certain studies with FERC on April 13, 2010, in abeyance pending resolutionresponse to the FERC order. PJM’s filing demonstrated that allocation of the Opinion 494 appeal discussed above. Now thatcost of high voltage transmission facilities on a beneficiary pays basis results in certain eastern utilities in PJM bearing the Seventh Circuit has ruledmajority of their costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the Opinion 494 case, AEPuse of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Certain eastern utilities and their state commissions supported continued socialization of these costs on a load ratio share basis. FERC have until November 11, 2009,is not expected to adviseact before the Seventh Circuitfourth quarter of any changes to their litigation positions that result from or reflect the Seventh Circuit’s decision in the Opinion 494 case.2010.

RTO Consolidation

On August 17, 2009,FERC issued an order approving, subject to certain future compliance filings, ATSI’s move to PJM. This allows 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 wouldwill 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. FERC approved FirstEnergy’s proposal to use a Fixed Resource Requirement Plan (FRR Plan) to obtain capacity to satisfy the PJM capacity requirements for the 2011-12 and 2012-13 delivery years.

To ensure a definitive ruling atIn December 2009, ATSI executed the same time FERC rules on its requestPJM Consolidated Transmission Owners Agreement and the Ohio Companies and Penn executed the PJM Operating Agreement and the PJM Reliability Assurance Agreement. Execution of these agreements committed ATSI and the Ohio Companies and Penn’s load to integrate ATSImoving into PJM on Octoberthe schedule described in the application and approved in the FERC Order.
FirstEnergy successfully conducted the FRR auctions on March 19, 2009, FirstEnergy filed a related complaint with FERC onand participated in the issue of allocating transmission costs toPJM base residual auction for the 2013 delivery year, thereby obtaining the capacity necessary for its ATSI footprint for high voltage transmission projects approved prior to FirstEnergy’s integration into PJM.

meet PJM’s capacity requirements. 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 whetherexpects 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 oneffective June 1, 2011, to coincide with delivery of power under the next competitive generation procurement process for FirstEnergy's Ohio companies.

2011.
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 forMISO Complaints Versus PJM Reliability Pricing Model (RPM) Auction

On May 30, 2008,March 9, 2010, MISO filed two complaints against PJM with FERC under Sections 206, 306 and 309 of the FPA alleging violations of the MISO/PJM Joint Operating Agreement (JOA). In Docket EL 10-46-000, the complaint alleges that PJM erroneously calculated charges to MISO for market-to-market settlements made from 2005 to 2009 pursuant to the congestion management provisions of the JOA. The MISO seeks approximately $130 million plus interest to correct for resultant net underpayments from PJM to MISO. In Docket No.EL10-45-000, MISO alleges that by failing to account for the market flows from 34 PJM generators over the period from 2007-2009, PJM underpaid MISO by a grouptotal of roughly $75 million including interest. For the period from 2005-2007, MISO claimed an underpayment by PJM load-serving entities, state commissions, consumer advocates,of at least $12 million plus interest. MISO also claimed that PJM failed to maintain required records necessary to calculate underbilling for the 2005-2007 billing.
In the second complaint, MISO alleged that PJM has refused to comply with provisions of the JOA requiring market-to-market dispatch since 2009, and trade associations (referredis improperly demanding repayment of redispatch payments previously made to collectively asMISO. PJM filed its answers to the RPM Buyers)complaints on April 12, 2010, opposing the relief sought by MISO.
In addition, on April 12, 2010, PJM filed a complaint at thewith FERC against PJMpursuant to Section 206, 306, and 309 alleging that three ofMISO is violating the four transitional RPM auctions yielded prices that are unjustJOA with PJM by initiating market-to-market coordination and unreasonable under the Federal Power Act. On September 19, 2008, the FERC denied the RPM Buyers’ complaint. The FERC also orderedfinancial settlements for substitute (proxy) reciprocal coordinated flowgates between MISO and PJM. 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 requestedclaims 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 couldJOA does 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.

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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 establishinitiate market-to-market settlements using proxy flowgates in lieu of designated reciprocal coordinated flowgates. This complaint addresses substantially the reserve margin requirement for load-serving entities based uponsame issues as the second MISO complaint, in which MISO argues that the use of proxy flowgates is permitted by agreement of the RTOs and operating practice. Each party filed a one day loss of loadcomplaint in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for load-serving entitiesorder to ensure their right to claim refunds, if any, if successful 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. their arguments at FERC.
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, 2009,29, 2010, FERC issued an order approvingconsolidating the cases and establishing settlement judge procedures. If the settlement process is unsuccessful, the cases will proceed to evidentiary hearings. FirstEnergy is unable to predict the outcome of this matter.

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MISO Multi-Value Project Rule Proposal
On July 15, 2010, MISO and certain MISO transmission owners jointly filed with the FERC their proposed cost allocation methodology for new transmission projects. If approved, so-called Multi Value Projects (MVPs) — transmission projects that have a MISO compliance filing that revised its tariffregional impact and are part of a regional plan — will have a 100% regional allocation of costs under the proposed methodology. If approved by FERC, MISO’s proposal is expected to provide for netting of demand resources, but prohibitingpermit the netting of behind-the-meter generation.

FES Sales to Affiliates

FES supplied allallocation of the power requirements forcosts of large transmission projects designed to integrate wind from the Ohio Companies pursuantupper Midwest across the entire MISO. MISO has requested a FERC response 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 acceptedfiling by the PUCO on May 14, 2009. Twelve bidders qualifiedFERC’s December open meeting, but an effective date for its proposal of July 16, 2011. Under MISO’s proposal, the costs of MVP projects approved by MISO’s Board prior 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 amount2011 effective date of capacity resources requiredFirstEnergy’s integration into PJM would continue to be supplied by FESallocated 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.FirstEnergy.

11.10. 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 2009,2010, the FASB amended the derecognition guidance in the TransfersDerivatives and ServicingHedging Topic of the FASB Accounting Standards Codification and eliminatedto clarify the conceptscope exception for embedded credit derivative features related to the transfer of a QSPE.credit risk in the form of subordination of one financial instrument to another. The amended guidance requires an evaluation of all existing QSPEsamendment addresses how to determine whether they mustwhich embedded credit derivative features, including those in collateralized debt obligations and synthetic collateralized debt obligations, are considered to be consolidated. This standardembedded derivatives that should not be analyzed under the Derivatives and Hedging Topic for potential bifurcation and separate accounting. The amendment is effective for financial asset transfers that occur inthe first fiscal yearsquarter beginning after NovemberJune 15, 2009.2010. 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.

11. SEGMENT INFORMATION
In August 2009, the FASB updated the Fair Value Measurement and Disclosures Topic, which provides guidanceFinancial information for each of FirstEnergy’s reportable segments is presented 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."table. FES and the Utilities do not have separate reportable operating segments.

With the completion of transition to a fully competitive generation market in Ohio in the fourth quarter of 2009, the former Ohio Transitional Generation Services segment was combined with the Energy Delivery Services segment, consistent with how management views the business. Disclosures for FirstEnergy’s operating segments for 2009 have been reclassified to conform to the current presentation.
The energy delivery servicesEnergy Delivery Services segment designs, constructs, operatestransmits and maintains FirstEnergy's regulated transmission and distribution systems and is responsible for the regulated generation commodity operationsdistributes electricity through FirstEnergy’s eight utility operating companies, serving 4.5 million customers within 36,100 square miles of FirstEnergy'sOhio, Pennsylvania and New Jersey electric utility subsidiaries.and purchases power for its POLR and default service requirements in Ohio, Pennsylvania and New Jersey. Its revenues are primarily derived from the delivery of electricity within FirstEnergy’s service areas, cost recovery of regulatory assets and default servicethe sale of electric generation salesservice to non-shoppingretail customers who have not selected an alternative supplier (default service) in its Ohio, 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 and MISO transmission expenses related to the delivery of thatthe respective generation load.

54



loads, and the deferral and amortization of certain fuel costs.
The competitive energy servicesCompetitive Energy Services segment supplies electric power to its electricend-use customers through retail and wholesale arrangements, including associated company power sales to meet all or a portion of the POLR and default service requirements of FirstEnergy’s Ohio and Pennsylvania utility affiliates, providessubsidiaries and competitive electricityretail sales to customers primarily in Ohio, Pennsylvania, Maryland Michigan and Illinois,Michigan. This business segment owns or leases and operates FirstEnergy's19 generating facilities with a net demonstrated capacity of 13,710 MWs and also purchases electricity to meet its sales obligations. The segment'ssegment’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 electricityenergy to the segment'ssegment’s customers. The segment's internal revenues represent sales to its affiliates in Ohio and Pennsylvania.

The Ohio transitional generation servicesother segment representscontains corporate items and other businesses that are below 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 throughquantifiable threshold for separate disclosure as 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.reportable segment.

53


                     
  Energy  Competitive           
  Delivery  Energy      Reconciling    
Segment Financial Information Services  Services  Other  Adjustments  Consolidated 
  (In millions) 
                     
Three Months Ended
                    
                     
June 30, 2010
                    
External revenues $2,373  $778  $6  $(29) $3,128 
Internal revenues  19   539      (558)   
                
Total revenues  2,392   1,317   6   (587)  3,128 
Depreciation and amortization  276   66   6   3   351 
Investment income (loss), net  27   13      (9)  31 
Net interest charges  123   31   3   10   167 
Income taxes  89   76   (22)  (9)  134 
Net income (loss)  143   125   16   (28)  256 
Total assets  22,450   11,100   591   325   34,466 
Total goodwill  5,551   24         5,575 
Property additions  172   282   7   28   489 
                     
June 30, 2009
                    
External revenues $2,792  $504  $5  $(30) $3,271 
Internal revenues     839      (839)   
                
Total revenues  2,792   1,343   5   (869)  3,271 
Depreciation and amortization  298   68   3   4   373 
Investment income (loss), net  35   6      (14)  27 
Net interest charges  113   18   2   40   173 
Income taxes  103   185   (20)  (20)  248 
Net income  154   276   18   (40)  408 
Total assets  23,215   10,144   684   263   34,306 
Total goodwill  5,551   24         5,575 
Property additions  178   248   70   (7)  489 
                     
Six Months Ended
                    
                     
June 30, 2010
                    
External revenues $4,916  $1,494  $10  $(60) $6,360 
Internal revenues*  19   1,213      (1,165)  67 
                
Total revenues  4,935   2,707   10   (1,225)  6,427 
Depreciation and amortization  601   132   19   4   756 
Investment income (loss), net  52   14      (19)  47 
Net interest charges  246   64   2   27   339 
Income taxes  158   123   (18)  (18)  245 
Net income (loss)  257   201   1   (54)  405 
Total assets  22,450   11,100   591   325   34,466 
Total goodwill  5,551   24         5,575 
Property additions  338   605   10   44   997 
                     
June 30, 2009
                    
External revenues $5,813  $839�� $12  $(59) $6,605 
Internal revenues     1,732      (1,732)   
                
Total revenues  5,813   2,571   12   (1,791)  6,605 
Depreciation and amortization  725   132   4   7   868 
Investment income (loss), net  65   (23)     (26)  16 
Net interest charges  222   36   3   78   339 
Income taxes  91   288   (37)  (40)  302 
Net income  136   431   35   (79)  523 
Total assets  23,215   10,144   684   263   34,306 
Total goodwill  5,551   24         5,575 
Property additions  343   669   119   12   1,143 
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 
*Under the accounting standard for the effects of certain types of regulation, internal revenues are not fully offset for sales of RECs by FES to the Ohio Companies that are retained in inventory.
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.

54


56



13.12. 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'sFGCO’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'strust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES'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-monththree month and nine-monthsix month periods ended SeptemberJune 30, 20092010 and 2008,2009, consolidating balance sheets as of SeptemberJune 30, 20092010 and December 31, 20082009 and consolidating statements of cash flows for the ninesix months ended SeptemberJune 30, 20092010 and 20082009 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'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.

55


FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME

(Unaudited)

                     
For the Three Months Ended June 30, 2010 FES  FGCO  NGC  Eliminations  Consolidated 
  (In thousands) 
                     
REVENUES
 $1,295,700  $580,621  $338,933  $(900,580) $1,314,674 
                
                     
EXPENSES:
                    
Fuel  7,268   300,867   34,276      342,411 
Purchased power from affiliates  912,858   7,163   49,457   (900,580)  68,898 
Purchased power from non-affiliates  298,820            298,820 
Other operating expenses  80,983   94,373   116,350   12,189   303,895 
Provision for depreciation  711   27,466   36,449   (1,307)  63,319 
General taxes  5,718   9,227   7,327      22,272 
                
Total expenses  1,306,358   439,096   243,859   (889,698)  1,099,615 
                
                     
OPERATING INCOME (LOSS)
  (10,658)  141,525   95,074   (10,882)  215,059 
                
                     
OTHER INCOME (EXPENSE):
                    
Investment income  1,811   81   11,474      13,366 
Miscellaneous income (expense), including net income from equity investees  151,291   709   102   (147,709)  4,393 
Interest expense to affiliates  (61)  (2,084)  (415)     (2,560)
Interest expense — other  (24,262)  (27,799)  (15,361)  16,050   (51,372)
Capitalized interest  98   19,573   4,234      23,905 
                
Total other income (expense)  128,877   (9,520)  34   (131,659)  (12,268)
                
                     
INCOME BEFORE INCOME TAXES
  118,219   132,005   95,108   (142,541)  202,791 
                     
INCOME TAXES (BENEFITS)
  (15,706)  48,465   33,550   2,557   68,866 
                
                     
NET INCOME
 $133,925  $83,540  $61,558  $(145,098) $133,925 
                

56


FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
                     
For the Six Months Ended June 30, 2010 FES  FGCO  NGC  Eliminations  Consolidated 
  (In thousands) 
                     
REVENUES
 $2,662,725  $1,148,985  $765,253  $(1,874,196) $2,702,767 
                
                     
EXPENSES:
                    
Fuel  12,365   581,730   76,537      670,632 
Purchased power from affiliates  1,881,395   12,242   110,410   (1,874,196)  129,851 
Purchased power from non-affiliates  749,035            749,035 
Other operating expenses  134,109   194,149   255,770   24,378   608,406 
Provision for depreciation  1,501   53,993   73,359   (2,616)  126,237 
General taxes  11,216   23,827   13,975      49,018 
                
Total expenses  2,789,621   865,941   530,051   (1,852,434)  2,333,179 
                
                     
OPERATING INCOME (LOSS)
  (126,896)  283,044   235,202   (21,762)  369,588 
                
                     
OTHER INCOME (EXPENSE):
                    
Investment income  3,708   135   10,240      14,083 
Miscellaneous income (expense), including net income from equity investees  317,664   (924)  1   (311,038)  5,703 
Interest expense to affiliates  (119)  (3,896)  (850)     (4,865)
Interest expense — other  (47,635)  (54,305)  (31,124)  32,048   (101,016)
Capitalized interest  198   35,906   7,491      43,595 
                
Total other income (expense)  273,816   (23,084)  (14,242)  (278,990)  (42,500)
                
                     
INCOME BEFORE INCOME TAXES
  146,920   259,960   220,960   (300,752)  327,088 
                     
INCOME TAXES (BENEFITS)
  (66,931)  96,508   78,563   5,097   113,237 
                
                     
NET INCOME
 $213,851  $163,452  $142,397  $(305,849) $213,851 
                

57


FIRSTENERGY SOLUTIONS CORP.
57CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
                     
For the Three Months Ended June 30, 2009 FES  FGCO  NGC  Eliminations  Consolidated 
  (In thousands) 
                     
REVENUES
 $1,067,987  $703,110  $389,695  $(819,640) $1,341,152 
                
                     
EXPENSES:
                    
Fuel  5,027   238,832   26,450      270,309 
Purchased power from affiliates  814,622   5,018   51,249   (819,640)  51,249 
Purchased power from non-affiliates  185,613            185,613 
Other operating expenses  35,771   99,145   131,159   12,189   278,264 
Provision for depreciation  1,017   30,191   35,654   (1,314)  65,548 
General taxes  3,769   11,332   6,184      21,285 
                
Total expenses  1,045,819   384,518   250,696   (808,765)  872,268 
                
                     
OPERATING INCOME
  22,168   318,592   138,999   (10,875)  468,884 
                
                     
OTHER INCOME (EXPENSE):
                    
Investment income  (518)  131   6,030      5,643 
Miscellaneous income (expense), including net income from equity investees  289,312   820      (282,510)  7,622 
Interest expense to affiliates  (34)  (1,623)  (1,658)     (3,315)
Interest expense — other  (2,900)  (24,967)  (14,677)  16,273   (26,271)
Capitalized interest  46   11,126   2,856      14,028 
                
Total other income (expense)  285,906   (14,513)  (7,449)  (266,237)  (2,293)
                
                     
INCOME BEFORE INCOME TAXES
  308,074   304,079   131,550   (277,112)  466,591 
                     
INCOME TAXES
  10,672   108,114   48,163   2,240   169,189 
                
                     
NET INCOME
 $297,402  $195,965  $83,387  $(279,352) $297,402 
                

58


FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

  ��                  
For the Six Months Ended June 30, 2009 FES  FGCO  NGC  Eliminations  Consolidated 
  (In thousands) 
                     
REVENUES
 $2,269,882  $1,249,036  $785,323  $(1,736,983) $2,567,258 
                
                     
EXPENSES:
                    
Fuel  7,122   513,679   55,666      576,467 
Purchased power from affiliates  1,729,883   7,100   114,456   (1,736,983)  114,456 
Purchased power from non-affiliates  345,955            345,955 
Other operating expenses  74,038   203,588   283,615   24,379   585,620 
Provision for depreciation  2,036   60,211   67,303   (2,629)  126,921 
General taxes  8,475   23,958   12,228      44,661 
                
Total expenses  2,167,509   808,536   533,268   (1,715,233)  1,794,080 
                
                     
OPERATING INCOME
  102,373   440,500   252,055   (21,750)  773,178 
                
                     
OTHER INCOME (EXPENSE):
                    
Investment income  214   162   (23,607)     (23,231)
Miscellaneous income (expense), including net income from equity investees  409,093   742      (399,702)  10,133 
Interest expense to affiliates  (68)  (3,381)  (2,845)     (6,294)
Interest expense — other  (5,420)  (46,025)  (29,845)  32,492   (48,798)
Capitalized interest  97   18,876   5,133      24,106 
                
Total other income (expense)  403,916   (29,626)  (51,164)  (367,210)  (44,084)
                
                     
INCOME BEFORE INCOME TAXES
  506,289   410,874   200,891   (388,960)  729,094 
                     
INCOME TAXES
  38,206   147,256   71,092   4,457   261,011 
                
                     
NET INCOME
 $468,083  $263,618  $129,799  $(393,417) $468,083 
                

59


FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
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 
                     
As of June 30, 2010 FES  FGCO  NGC  Eliminations  Consolidated 
  (In thousands) 
                     
ASSETS                    
CURRENT ASSETS:
                    
Cash and cash equivalents $  $2  $9  $  $11 
Receivables—                    
Customers  315,178            315,178 
Associated companies  327,070   257,268   89,725   (319,936)  354,127 
Other  24,815   6,946   4,631      36,392 
Notes receivable from associated companies  84,337      89,594      173,931 
Materials and supplies, at average cost  23,804   333,709   221,008      578,521 
Prepayments and other  162,845   5,600   4,069      172,514 
                
   938,049   603,525   409,036   (319,936)  1,630,674 
                
                     
PROPERTY, PLANT AND EQUIPMENT:
                    
In service  93,403   5,588,112   5,203,976   (385,086)  10,500,405 
Less — Accumulated provision for depreciation  15,742   2,824,150   2,028,479   (173,191)  4,695,180 
                
   77,661   2,763,962   3,175,497   (211,895)  5,805,225 
Construction work in progress  7,412   2,149,132   466,321      2,622,865 
                
   85,073   4,913,094   3,641,818   (211,895)  8,428,090 
                
                     
INVESTMENTS:
                    
Nuclear plant decommissioning trusts        1,107,594      1,107,594 
Investment in associated companies  4,790,066         (4,790,066)   
Other  759   7,003   203      7,965 
                
   4,790,825   7,003   1,107,797   (4,790,066)  1,115,559 
                
                     
DEFERRED CHARGES AND OTHER ASSETS:
                    
Accumulated deferred income taxes  78,986   340,072      (419,058)   
Customer intangibles  118,219            118,219 
Goodwill  24,248            24,248 
Property taxes     27,811   22,314      50,125 
Unamortized sale and leaseback costs     14,168      63,478   77,646 
Other  102,829   76,609   9,655   (60,778)  128,315 
                
   324,282   458,660   31,969   (416,358)  398,553 
                
  $6,138,229  $5,982,282  $5,190,620  $(5,738,255) $11,572,876 
                
                     
LIABILITIES AND CAPITALIZATION                    
                     
CURRENT LIABILITIES:
                    
Currently payable long-term debt $755  $472,357  $927,772  $(19,101) $1,381,783 
Short-term borrowings—                    
Associated companies     85,128         85,128 
Other  100,000            100,000 
Accounts payable—                    
Associated companies  311,959   257,889   154,508   (311,849)  412,507 
Other  101,776   134,944         236,720 
Accrued taxes  1,717   74,125   54,576   (21,336)  109,082 
Other  216,207   102,780   15,377   34,722   369,086 
                
   732,414   1,127,223   1,152,233   (317,564)  2,694,306 
                
                     
CAPITALIZATION:
                    
Common stockholder’s equity  3,731,382   2,504,419   2,268,860   (4,773,279)  3,731,382 
Long-term debt and other long-term obligations  1,518,968   1,820,112   506,533   (1,259,694)  2,585,919 
                
   5,250,350   4,324,531   2,775,393   (6,032,973)  6,317,301 
                
                     
NONCURRENT LIABILITIES:
                    
Deferred gain on sale and leaseback transaction           976,012   976,012 
Accumulated deferred income taxes        373,725   (363,730)  9,995 
Accumulated deferred investment tax credits     34,820   21,490      56,310 
Asset retirement obligations     26,196   837,213      863,409 
Retirement benefits  35,830   188,023         223,853 
Property taxes     27,811   22,314      50,125 
Lease market valuation liability     239,447         239,447 
Other  119,635   14,231   8,252      142,118 
                
   155,465   530,528   1,262,994   612,282   2,561,269 
                
  $6,138,229  $5,982,282  $5,190,620  $(5,738,255) $11,572,876 
                

60


FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
                     
As of December 31, 2009 FES  FGCO  NGC  Eliminations  Consolidated 
  (In thousands) 
ASSETS                    
CURRENT ASSETS:
                    
Cash and cash equivalents $  $3  $9  $  $12 
Receivables-                    
Customers  195,107            195,107 
Associated companies  305,298   175,730   134,841   (297,308)  318,561 
Other  28,394   10,960   12,518      51,872 
Notes receivable from associated companies  416,404   240,836   147,863      805,103 
Materials and supplies, at average cost  17,265   307,079   215,197      539,541 
Prepayments and other  80,025   18,356   9,401      107,782 
                
   1,042,493   752,964   519,829 �� (297,308)  2,017,978 
                
                     
PROPERTY, PLANT AND EQUIPMENT:
                    
In service  90,474   5,478,346   5,174,835   (386,023)  10,357,632 
Less — Accumulated provision for depreciation  13,649   2,778,320   1,910,701   (171,512)  4,531,158 
                
   76,825   2,700,026   3,264,134   (214,511)  5,826,474 
Construction work in progress  6,032   2,049,078   368,336      2,423,446 
                
   82,857   4,749,104   3,632,470   (214,511)  8,249,920 
                
                     
INVESTMENTS:
                    
Nuclear plant decommissioning trusts        1,088,641      1,088,641 
Investment in associated companies  4,477,602         (4,477,602)   
Other  1,137   21,127   202      22,466 
                
   4,478,739   21,127   1,088,843   (4,477,602)  1,111,107 
                
                     
DEFERRED CHARGES AND OTHER ASSETS:
                    
Accumulated deferred income taxes  93,379   381,849      (388,602)  86,626 
Customer intangibles  16,566            16,566 
Goodwill  24,248            24,248 
Property taxes     27,811   22,314      50,125 
Unamortized sale and leaseback costs     16,454      56,099   72,553 
Other  82,845   71,179   18,755   (51,114)  121,665 
                
   217,038   497,293   41,069   (383,617)  371,783 
                
  $5,821,127  $6,020,488  $5,282,211  $(5,373,038) $11,750,788 
                
                     
LIABILITIES AND CAPITALIZATION                    
                     
CURRENT LIABILITIES:
                    
Currently payable long-term debt $736  $646,402  $922,429  $(18,640) $1,550,927 
Short-term borrowings—                    
Associated companies     9,237         9,237 
Other  100,000            100,000 
Accounts payable—                    
Associated companies  261,788   170,446   295,045   (261,201)  466,078 
Other  51,722   193,641         245,363 
Accrued taxes  44,213   61,055   22,777   (44,887)  83,158 
Other  173,015   132,314   16,734   36,994   359,057 
                
   631,474   1,213,095   1,256,985   (287,734)  2,813,820 
                
                     
CAPITALIZATION:
                    
Common stockholder’s equity  3,514,571   2,346,515   2,119,488   (4,466,003)  3,514,571 
Long-term debt and other long-term obligations  1,519,339   1,906,818   554,825   (1,269,330)  2,711,652 
                
   5,033,910   4,253,333   2,674,313   (5,735,333)  6,226,223 
                
                     
NONCURRENT LIABILITIES:
                    
Deferred gain on sale and leaseback transaction           992,869   992,869 
Accumulated deferred income taxes        342,840   (342,840)   
Accumulated deferred investment tax credits     36,359   22,037      58,396 
Asset retirement obligations     25,714   895,734      921,448 
Retirement benefits  33,144   170,891         204,035 
Property taxes     27,811   22,314      50,125 
Lease market valuation liability     262,200         262,200 
Other  122,599   31,085   67,988      221,672 
                
   155,743   554,060   1,350,913   650,029   2,710,745 
                
  $5,821,127  $6,020,488  $5,282,211  $(5,373,038) $11,750,788 
                

61


58
FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
                     
For the Six Months Ended June 30, 2010 FES  FGCO  NGC  Eliminations  Consolidated 
  (In thousands) 
                     
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES
 $(223,072) $163,325  $287,376  $(9,174) $218,455 
                
                     
CASH FLOWS FROM FINANCING ACTIVITIES:
                    
New Financing—                    
Short-term borrowings, net     75,891         75,891 
Redemptions and Repayments—                    
Long-term debt  (397)  (260,865)  (42,949)  9,174   (295,037)
Short-term borrowings, net               
Other  (457)  (128)  (101)     (686)
                
Net cash used for financing activities  (854)  (185,102)  (43,050)  9,174   (219,832)
                
                     
CASH FLOWS FROM INVESTING ACTIVITIES:
                    
Property additions  (3,716)  (333,063)  (229,408)     (566,187)
Proceeds from asset sales     115,657         115,657 
Sales of investment securities held in trusts        956,813      956,813 
Purchases of investment securities held in trusts        (978,785)     (978,785)
Loans from associated companies, net  332,067   240,836   58,270      631,173 
Customer acquisition costs  (104,795)           (104,795)
Leasehold improvement payments to associated companies        (51,204)     (51,204)
Other  370   (1,654)  (12)     (1,296)
                
Net cash provided from (used for) investing activities  223,926   21,776   (244,326)     1,376 
                
                     
Net change in cash and cash equivalents     (1)        (1)
Cash and cash equivalents at beginning of period     3   9      12 
                
Cash and cash equivalents at end of period $  $2  $9  $  $11 
                

62


FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
                     
For the Six Months Ended June 30, 2009 FES  FGCO  NGC  Eliminations  Consolidated 
  (In thousands) 
                     
NET CASH PROVIDED FROM OPERATING ACTIVITIES
 $285,284  $314,041  $221,625  $(8,734) $812,216 
                
                     
CASH FLOWS FROM FINANCING ACTIVITIES:
                    
New Financing—                    
Long-term debt     347,710   333,965      681,675 
Short-term borrowings, net  98,880      128,716   (82,587)  145,009 
Redemptions and Repayments—                   
Long-term debt  (1,696)  (260,372)  (369,519)  8,734   (622,853)
Short-term borrowings, net     (82,587)     82,587    
                
Net cash provided from financing activities  97,184   4,751   93,162   8,734   203,831 
                
                     
CASH FLOWS FROM INVESTING ACTIVITIES:
                    
Property additions  (694)  (332,789)  (301,484)     (634,967)
Proceeds from asset sales     15,771         15,771 
Sales of investment securities held in trusts        537,078      537,078 
Purchases of investment securities held in trusts        (550,730)     (550,730)
Loans to associated companies, net  (261,839)  20,669         (241,170)
Other  65   (22,448)  349      (22,034)
                
Net cash used for investing activities  (262,468)  (318,797)  (314,787)     (896,052)
                
                     
Net change in cash and cash equivalents  120,000   (5)        119,995 
Cash and cash equivalents at beginning of period     39         39 
                
Cash and cash equivalents at end of period $120,000  $34  $  $  $120,034 
                
13. INTANGIBLE ASSETS
FES has acquired certain customer contract rights, which were capitalized as intangible assets. These rights allow FES to supply electric generation needs to customers and the recorded value is being amortized ratably over the term of the related contracts. Net intangible assets of $118 million are included in other assets on FirstEnergy’s Consolidated Balance Sheet as of June 30, 2010.
For the three and six months ended June 30, 2010, amortization expense was approximately $3 million and $5 million, respectively.


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 
14. ASSET RETIREMENT OBLIGATIONS

FirstEnergy has recognized applicable legal obligations for AROs and their associated cost for nuclear power plant decommissioning, reclamation of a sludge disposal pond and closure of two coal ash disposal sites. In addition, FirstEnergy has recognized conditional asset retirement obligations (primarily for asbestos remediation).
The ARO liabilities for FES, OE and TE primarily relate to the decommissioning of the Beaver Valley, Davis-Besse and Perry nuclear generating facilities (OE for their leasehold interest in Beaver Valley Unit 2 and Perry and TE for its leasehold interest in Beaver Valley Unit 2). The ARO liabilities for JCP&L, Met-Ed and Penelec primarily relate to the decommissioning of the TMI-2 nuclear generating facility. FES and the Utilities use an expected cash flow approach to measure the fair value of their nuclear decommissioning AROs.
During the second quarter of 2010, studies were completed to reassess the estimated cost of decommissioning the Beaver Valley nuclear generating facility. The cost studies resulted in a revision to the estimated cash flows associated with the ARO liabilities of FES, OE and TE and reduced the liability for each subsidiary in the amounts of $88 million, $7 million, and $5 million, respectively, as of June 30, 2010.
The revision to the estimated cash flows had no significant impact on accretion expense during the second quarter of 2010 when compared to the second quarter of 2009.

63


15. PROPOSED MERGER WITH ALLEGHENY ENERGY, INC.
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




ReportAs previously disclosed, on February 10, 2010, FirstEnergy entered into an Agreement and Plan 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.Merger, subsequently amended on June 4, 2010 (Merger Agreement) with Element Merger Sub, Inc., a Maryland corporation and its subsidiaries as of September 30, 2009wholly-owned subsidiary (Merger Sub) and Allegheny Energy, Inc., a Maryland corporation (Allegheny Energy). Upon the related consolidated statements of incometerms 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 madesubject 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 informationconditions set forth in the accompanying consolidated balance sheet informationMerger Agreement, Merger Sub will merge with and into Allegheny Energy with Allegheny Energy continuing as the surviving corporation and a wholly-owned subsidiary of December 31, 2008, is fairly stated in all material respects in relationFirstEnergy. Pursuant to the consolidated balance sheet fromMerger Agreement, upon the closing of the merger, each issued and outstanding share of Allegheny Energy common stock, including grants of restricted common stock, will automatically be converted into the right to receive 0.667 of a share of common stock of FirstEnergy and Allegheny Energy stockholders will own approximately 27% of the combined company. Based on the closing stock prices for both companies on February 10, 2010, Allegheny Energy shareholders would receive a value of $27.65 per share. On July 15, 2010 the most recent practicable date prior to the effectiveness of the Form S-4 registration statement, the exchange ratio represented approximately $25.06 in value for each share of Allegheny Energy common stock. FirstEnergy will also assume all outstanding Allegheny Energy debt.
Pursuant to the Merger Agreement, completion of the merger is conditioned upon, among other things, shareholder approval of both companies, the SEC’s clearance of a registration statement registering the FirstEnergy common stock to be issued in connection with the merger, as well as expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and approval by the FERC, the MDPSC, the PPUC, the VSCC and the PSCWV. The Merger Agreement also contains certain termination rights for both FirstEnergy and Allegheny Energy, and further provides for the payment of fees and expenses upon termination under specified circumstances.
FirstEnergy and Allegheny Energy currently anticipate completing the merger in the first half of 2011. Although FirstEnergy and Allegheny Energy believe that they will receive the required authorizations, approvals and consents to complete the merger, there can be no assurance as to the timing of these authorizations, approvals and consents or as to FirstEnergy’s and Allegheny Energy’s ultimate ability to obtain such authorizations, consents or approvals (or any additional authorizations, approvals or consents which it has been derived.may otherwise become necessary) or that such authorizations, approvals or consents will be obtained on terms and subject to conditions satisfactory to Allegheny Energy and FirstEnergy. Further information concerning the proposed merger is included in the Registration Statement filed by FirstEnergy with the SEC in connection with the merger.
In connection with the proposed merger, FirstEnergy recorded approximately $7 million ($5 million after tax) of merger transaction costs in the second quarter and approximately $21 million ($15 million after tax) of merger transaction costs in the first six months of 2010. These costs are expensed as incurred.

64


Item 2.
PricewaterhouseCoopers LLP
Cleveland, Ohio
November 6, 2009Management’s Discussion and Analysis of Registrant and Subsidiaries




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




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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




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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





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


FIRSTENERGY CORP.

MANAGEMENT'SMANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS


EXECUTIVE SUMMARY

Net incomeEarnings available to FirstEnergy in the thirdsecond quarter of 2009 was $2342010 were $265 million, or basic and diluted earnings of $0.77$0.87 per share of common stock, compared with net income$414 million, or basic and diluted earnings of $471$1.36 per share of common stock in the second quarter of 2009. Results in the second quarter of 2010 were adversely affected by the absence of a 2009 gain from the sale of a 9% participation interest in OVEC. Earnings available to FirstEnergy in the first six months of 2010 were $420 million or basic earnings of $1.55$1.38 ($1.37 diluted) 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 $768compared with $533 million, or basic and diluted earnings of $2.52$1.75 per share of common stock ($2.51 diluted)in the first six months of 2009.
         
  Three Months  Six Months 
Change in Basic Earnings Per Share From Prior Year Ended June 30  Ended June 30 
         
Basic Earnings Per Share — 2009 $1.36  $1.75 
Non-core asset sales/impairments  (0.52)  (0.54)
Trust securities impairments  (0.01)  0.04 
Regulatory charges — 2009     0.55 
Regulatory charges — 2010     (0.08)
Derivative mark-to-market adjustment — 2010  0.07   (0.04)
Organizational restructuring — 2009  0.01   0.06 
Merger transaction costs — 2010  (0.02)  (0.05)
Litigation settlements  0.04   0.04 
Debt call premium — 2009  0.01   0.01 
Income tax resolution — 2009     (0.04)
Income tax charge from healthcare legislation — 2010     (0.04)
Revenues  0.23   0.16 
Fuel and purchased power  (0.28)  (0.41)
Transmission expense  (0.08)  0.02 
Amortization of regulatory assets, net  0.06   (0.11)
Investment income  0.02   0.03 
Other expenses  (0.02)  0.03 
       
Basic Earnings Per Share — 2010 $0.87  $1.38 
       
Pending Merger
As previously disclosed, on February 10, 2010, FirstEnergy entered into an Agreement and Plan of Merger, subsequently amended on June 4, 2010, (Merger Agreement) with Element Merger Sub. Inc., compareda Maryland corporation and its wholly-owned subsidiary (Merger Sub) and Allegheny Energy, Inc., a Maryland corporation (Allegheny Energy). Upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with net incomeand into Allegheny Energy with Allegheny Energy continuing as the surviving corporation and a wholly-owned subsidiary of $1.01 billion, or basic earningsFirstEnergy. Pursuant to the Merger Agreement, upon the closing of $3.32 perthe merger, each issued and outstanding share of Allegheny Energy common stock, including grants of restricted common stock, will automatically be converted into the right to receive 0.667 of a share of common stock ($3.29 diluted)of FirstEnergy and Allegheny Energy stockholders will own approximately 27% of the combined company. Based on the closing stock prices for both companies on February 10, 2010, Allegheny Energy shareholders would receive a value of $27.65 per share. On July 15, 2010, the most recent practicable date prior to the effectiveness of the Form S-4 registration statement, the exchange ratio represented approximately $25.06 in value for each share of Allegheny Energy common stock. FirstEnergy will also assume all outstanding Allegheny Energy debt.
Pursuant to the Merger Agreement, completion of the merger is conditioned upon, among other things, shareholder approval of both companies, the SEC’s clearance of a registration statement registering the FirstEnergy common stock to be issued in connection with the merger, as well as expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and approval by the FERC, the MDPSC, the PPUC, the VSCC and the PSCWV. The Merger Agreement also contains certain termination rights for both FirstEnergy and Allegheny Energy, and further provides for the payment of fees and expenses upon termination under specified circumstances.

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FirstEnergy and Allegheny Energy currently anticipate completing the merger in the first nine monthshalf 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, 2009,2011. Although FirstEnergy and Allegheny Energy believe that they will receive 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 forecastingrequired authorizations, approvals 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.

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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.

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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 costconsents to complete the projectmerger, there can be no assurance as to the timing of these authorizations, approvals and consents or as to FirstEnergy’s and Allegheny Energy’s ultimate ability to obtain such authorizations, consents or approvals (or any additional authorizations, approvals or consents which may otherwise become necessary) or that such authorizations, approvals or consents will be $180 million.obtained on terms and subject to conditions satisfactory to Allegheny Energy and FirstEnergy. Further information concerning the proposed merger is included in the Registration Statement filed by FirstEnergy with the SEC in connection with the merger.

In connection with the proposed merger, FirstEnergy recorded approximately $7 million ($5 million after tax) of merger transaction costs in the second quarter and approximately $21 million ($15 million after tax) of merger transaction costs in the first six months of 2010. These costs are expensed as incurred.
Nuclear Outage

FERC
On October 12, 2009, NGC's Beaver Valley Nuclear Power Station Unit 2, located in Shippingport, Pennsylvania began a scheduled refuelingMay 11, 2010, FirstEnergy 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, FirstEnergyAllegheny Energy filed an application with the FERC for approval of their proposed merger. Under the Federal Power Act, FERC has 180 days to consolidate its transmission assetsrule on the merger application. FirstEnergy and operations into PJM. Currently FirstEnergy's transmission assetsAllegheny Energy submitted additional information regarding the merger application on June 21, 2010 in response to a request by FERC. Interventions 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 customersprotests were filed with the benefitsFERC on July 12, 2010.
State Regulatory Merger Filings
On May 14 and May 18, 2010, FirstEnergy and Allegheny Energy filed applications with the PPUC and the PSCWV, respectively, for approval of their proposed merger. Pennsylvania and West Virginia laws impose no statutory timeframe for their commissions’ consideration of a more fully developed retail choice market,merger application, but procedural schedules have been established, and final decisions are anticipated early in 2011. On May 27, 2010, 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, FirstEnergyAllegheny Energy filed an application for economic stimulus fundingapproval of the proposed merger with the U.S. DepartmentMDPSC. The MDPSC is required to issue an order no later than 180 days after an application is filed, but under good cause MDPSC may give itself a 45-day extension, which it did when it issued its initial order in the matter. An order from the MDPSC is therefore expected by January 7, 2011. On June 14, 2010, FirstEnergy and Allegheny Energy completed their application with the VSCC. The VSCC is required to rule on the merger application in 60 days, subject to up to a 120-day extension. In its order issued June 25, 2010, the VSCC extended the period for its review by 30 days; therefore the companies expect a decision by September 13, 2010.
Hart-Scott-Rodino (HSR) Act Filings
On May 25, 2010, FirstEnergy and Allegheny Energy made HSR filings with the DOJ and Federal Trade Commission. On June 24, 2010, FirstEnergy and Allegheny Energy each received a request for additional information from the DOJ, which extends the HSR Act waiting period for an additional 30 days from the date that the requested information is supplied to the DOJ.
Form S-4 Registration Statement
On July 16, 2010, FirstEnergy’s registration statement on Form S-4 containing a joint proxy statement/prospectus relating to the proposed merger (Registration Statement) was declared effective by the SEC. The joint proxy statement/prospectus contained in the Registration Statement was first mailed to FirstEnergy and Allegheny Energy shareholders on or about July 23, 2010. FirstEnergy and Allegheny Energy will each hold a special meeting of Energy undershareholders on September 14, 2010 in connection with the proposed merger.
Financial Matters
Financing Activities
On June 1, 2010, FGCO purchased $15 million fixed rate of PCRBs originally issued on its behalf. Subject to market conditions, FGCO plans to remarket the $15 million of PCRBs, as well as $235 million of PCRBs purchased in April, in the near future.
Penn redeemed $1 million of PCRBs due October 1, 2013 on June 1, 2010 and $6.5 million of 7.65% FMBs due in 2023 on July 30, 2010.
During the second quarter of 2010, FirstEnergy executed 13 interest rate swap contracts totaling $3.2 billion. These contacts were subsequently terminated to take advantage of favorable market conditions, and resulted in cash proceeds of $126.7 million. These proceeds will generally be amortized to earnings over the life of the underlying debt.

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Operational Matters
Davis-Besse Refueling
On June 3, 2010, modifications of 24 of the 69 control rod drive mechanism (CRDM) nozzles on the reactor head were completed at the Davis-Besse Nuclear Power Station. These nozzles were identified during Davis-Besse’s refueling outage and reactor head inspection that began February 28, 2010. The extended outage at Davis-Besse resulted in a $5 million impact on O&M this quarter, while approximately $40 million of the costs related to the modifications to the CRDM were capitalized. The plant was originally scheduled to have a new reactor head installed in 2014. This timeline was voluntarily accelerated, and FirstEnergy announced that a new reactor head will be installed in the fall of 2011. The new head was manufactured in France and is expected to arrive at the plant in the fall of 2010 to undergo a series of pre-service inspections. Davis-Besse returned to service on June 29, 2010.
Legacy Power Contracts
In July 2010, FES entered into financial transactions that offset the mark-to-market impact of legacy purchased power contracts totaling 500 MW entered into in 2008 for delivery in 2010 and 2011 and which were marked to market beginning in December 2009. These financial transactions eliminate the volatility associated with marking these contracts to market through the end of 2011.
Regulatory Matters — General
DOE Smart Grid Grants
On June 3, 2010, FirstEnergy and the DOE signed grants totaling $57.4 million that were awarded as part of the American Recovery and Reinvestment Act that proposed investing $114 million onto introduce smart grid technologies to improve the reliabilityin targeted areas in Pennsylvania, Ohio, and interactivity of its electric distribution infrastructure in its three-state service area.New Jersey. The application requested $57 million, which represents halfDOE grants represent 50% of the funding needed for targeted projectsthe $114.9 million FirstEnergy investment in communities served bysmart grid technologies; the Utilities. On October 27, 2009,PPUC and the NJBPU have already approved recovery for the remaining portion of smart grid costs. The PUCO issued an order on June 30, 2010, approving FirstEnergy’s smart grid program, but 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.

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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 issuancehas delayed implementation 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 $300 million of FMB that bear interest at an annual rate of 5.5% and mature on August 15, 2024. AOhio portion of the proceedsprogram until there is more certainty regarding cost recovery for the portion of the costs not covered by the grant.
Regulatory Matters — Ohio
Electric Security Plan Filing
The Ohio Companies filed a second Supplemental Stipulation with the PUCO on July 22, 2010, to supplement the ESP Stipulation filed on March 23, 2010, and the Supplemental Stipulation filed on May 13, 2010. An additional four signatories were included in the Supplemental Stipulations, joining the Ohio Companies and 17 original signatory parties that support the ESP. A final PUCO order is pending.
Regulatory Matters — Pennsylvania
Met-Ed and Penelec TSC
On May 20, 2010, the PPUC approved the revised TSC for Met-Ed and Penelec. The revised TSC rates were slightly increased for Met-Ed and slightly decreased for Penelec, and are effective for the period of June 1, 2010 to December 31, 2010. The PPUC’s Order of March 3, 2010, which denies the recovery of marginal transmission losses through the TSC for the period of June 1, 2007 through March 31, 2008, remains subject to an appeal that is currently pending in the Commonwealth Court of Pennsylvania.
Met-Ed and Penelec Default Service Plan
On May 27, 2010, the third of four auctions held to procure the default service requirements for Met-Ed and Penelec customers who choose not to shop with an alternative supplier. For the five-month period of January 1, 2011 to May 31, 2011, the tranche-weighted average prices ($/MWh) for Met-Ed’s residential and commercial classes were $72.81 and $72.29, respectively; Penelec’s tranche-weighted average prices were $62.04 and $63.35 for its residential and commercial classes, respectively. There will be usedanother auction in October 2010 to replace $150 millionprocure the remaining supply for this period. The May 2010 auction was also the first of CEI’s 7.43% Series D Secured Notes that mature on Novemberfour auctions to procure commercial default service requirements for the 12-month period of June 1, 2009.2011, to May 31, 2012 and residential requirements for the 24-month period of June 1, 2011, to May 31, 2013. For Met-Ed and Penelec commercial customers the tranche-weighted average price ($/MWh) was $66.32 and $57.60, respectively. The remaining proceeds were used to repay a portion of CEI’s short-term borrowings.three auctions for these products will be conducted in October 2010, January 2011 and March 2011.

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RPM Base Residual Auction
On September 2, 2009,May 14, 2010, PJM released the Utilities and ATSI voluntarily contributed $500 million toresults of the pension plan. On September 30, 2009, Penelec issued $500 million2013/2014 RPM Base Residual Auction. The auction cleared 152,743 MW 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 PCRBsunforced capacity in the near future.RTO Zone, which includes the ATSI zone, at the Resource Clearing Price of $27.73/MW-day. The Clearing Price in MAAC, which includes Met-Ed and Penelec zones and EMAAC which includes the Jersey Central zone, were $226.15/MW-day and $245.00/MW-day, respectively.

FIRSTENERGY'SFIRSTENERGY’S BUSINESS

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

Energy Delivery Servicestransmits and distributes electricity through our 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 POLR and default service requirements in Ohio, Pennsylvania and New Jersey. Its revenues are primarily derived from the delivery of electricity within our service areas, cost recovery of regulatory assets and the sale of electric generation service to retail customers who have not selected an alternative supplier (default service) in its Ohio, Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES and from non-affiliated power suppliers, the net PJM and MISO transmission expenses related to the delivery of the respective generation loads, and the deferral and amortization of certain fuel costs.
·  
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 Servicessupplies electric power to end-use customers through retail and wholesale arrangements, including associated company power sales to meet all or a portion of the POLR and default service requirements of our Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland and Michigan. This business segment controls approximately 14,000 MW of capacity and also purchases electricity to meet 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 energy to the segment’s customers.

·  
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'sFirstEnergy’s business segments. A reconciliation of segment financial results is provided in Note 1211 to the consolidated financial statements. Earnings available to FirstEnergy by major business segment were as follows:

                         
  Three Months Ended  Six Months Ended 
  June 30  June 30 
          Increase          Increase 
  2010  2009  (Decrease)  2010  2009  (Decrease) 
  (In millions, except per share data) 
Earnings By Business Segment:
                        
Energy delivery services $143  $154  $(11) $257  $136  $121 
Competitive energy services  125   276   (151)  201   431   (230)
Other and reconciling adjustments*  (3)  (16)  13   (38)  (34)  (4)
                   
Total $265  $414  $(149) $420  $533  $(113)
                   
                         
Basic Earnings Per Share
 $0.87  $1.36  $(0.49) $1.38  $1.75  $(0.37)
Diluted Earnings Per Share
 $0.87  $1.36  $(0.49) $1.37  $1.75  $(0.38)
*Consists primarily of interest expense related to holding company debt, corporate support services revenues and expenses, noncontrolling interests and the elimination of intersegment transactions.

68


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— Second Quarter 20092010 Compared with ThirdSecond Quarter 2008

2009
Financial results for FirstEnergy'sFirstEnergy’s major business segments in the thirdsecond quarter of 20092010 and 20082009 were as follows:

                 
  Energy  Competitive  Other and    
  Delivery  Energy  Reconciling  FirstEnergy 
Second Quarter 2010 Financial Results Services  Services  Adjustments  Consolidated 
  (In millions) 
Revenues:                
External                
Electric $2,243  $728  $  $2,971 
Other  130   50   (23)  157 
Internal  19   539   (558)   
             
Total Revenues  2,392   1,317   (581)  3,128 
             
                 
Expenses:                
Fuel     351   (1)  350 
Purchased power  1,291   319   (558)  1,052 
Other operating expenses  352   337   (16)  673 
Provision for depreciation  115   66   9   190 
Amortization of regulatory assets  161         161 
Deferral of new regulatory assets            
General taxes  145   25   6   176 
             
Total Expenses  2,064   1,098   (560)  2,602 
             
                 
Operating Income  328   219   (21)  526 
             
Other Income (Expense):                
Investment income  27   13   (9)  31 
Interest expense  (124)  (55)  (28)  (207)
Capitalized interest  1   24   15   40 
             
Total Other Expense  (96)  (18)  (22)  (136)
             
                 
Income Before Income Taxes  232   201   (43)  390 
Income taxes  89   76   (31)  134 
             
Net Income (Loss)  143   125   (12)  256 
Noncontrolling interest loss        (9)  (9)
             
Earnings available to FirstEnergy Corp. $143  $125  $(3) $265 
             

69


                 
  Energy  Competitive  Other and    
  Delivery  Energy  Reconciling  FirstEnergy 
Second Quarter 2009 Financial Results Services  Services  Adjustments  Consolidated 
  (In millions) 
                 
Revenues:                
External                
Electric $2,657  $205  $  $2,862 
Other  135   299   (25)  409 
Internal     839   (839)   
             
Total Revenues  2,792   1,343   (864)  3,271 
             
                 
Expenses:                
Fuel     276      276 
Purchased power  1,677   186   (839)  1,024 
Other operating expenses  328   315   (31)  612 
Provision for depreciation  110   68   7   185 
Amortization of regulatory assets  233         233 
Deferral of new regulatory assets  (45)        (45)
General taxes  154   25   5   184 
             
Total Expenses  2,457   870   (858)  2,469 
             
                 
Operating Income  335   473   (6)  802 
             
Other Income (Expense):                
Investment income  35   6   (14)  27 
Interest expense  (114)  (32)  (60)  (206)
Capitalized interest  1   14   18   33 
             
Total Other Expense  (78)  (12)  (56)  (146)
             
                 
Income Before Income Taxes  257   461   (62)  656 
Income taxes  103   185   (40)  248 
             
Net Income (Loss)  154   276   (22)  408 
Noncontrolling interest loss        (6)  (6)
             
Earnings available to FirstEnergy Corp. $154  $276  $(16) $414 
             
       Ohio                       
 Energy  Competitive  Transitional  Other and    
 Delivery  Energy  Generation  Reconciling  FirstEnergy 
Third Quarter 2009 Financial Results Services  Services  Services  Adjustments  Consolidated 
Changes Between Second Quarter 2010 and         
Second Quarter 2009 Financial Results         
Increase (Decrease)         
 (In millions)  
Revenues:                
External                
Electric $2,067  $444  $737  $-  $3,248  $(414) $523 $ $109 
Other  136   46   2   (24)  160   (5)  (249) 2  (252)
Internal  -   617   -   (617)  -  19  (300) 281  
         
Total Revenues  2,203   1,107   739   (641)  3,408   (400)  (26) 283  (143)
         
                     
Expenses:                     
Fuel  -   302   -   -   302   75  (1) 74 
Purchased power  1,011   205   714   (617)  1,313   (386) 133 281 28 
Other operating expenses  373   331   (9)  (30)  665  24 22 15 61 
Provision for depreciation  112   69   -   7   188  5  (2) 2 5 
Amortization of regulatory assets  244   -   17   -   261   (72)    (72)
Deferral of new regulatory assets  -   -   -   -   -  45   45 
General taxes  160   27   2   3   192   (9)  1  (8)
         
Total Expenses  1,900   934   724   (637)  2,921   (393) 228 298 133 
                             
 
Operating Income  303   173   15   (4)  487   (7)  (254)  (15)  (276)
         
Other Income (Expense):                     
Investment income  46   159   -   (14)  191   (8) 7 5 4 
Interest expense  (118)  (46)  -   (191)  (355)  (10)  (23) 32  (1)
Capitalized interest  1   18   -   16   35   10  (3) 7 
         
Total Other Expense  (71)  131   -   (189)  (129)  (18)  (6) 34 10 
         
                     
Income Before Income Taxes  232   304   15   (193)  358   (25)  (260) 19  (266)
Income taxes  93   121   6   (92)  128   (14)  (109) 9  (114)
Net Income  139   183   9   (101)  230 
Less: Noncontrolling interest income (loss)  -   -   -   (4)  (4)
         
Net Income (Loss)  (11)  (151) 10  (152)
Noncontrolling interest loss    (3)  (3)
         
Earnings available to FirstEnergy Corp. $139  $183  $9  $(97) $234  $(11) $(151) $13 $(149)
         

70



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— Second Quarter 20092010 Compared with ThirdSecond Quarter 20082009

Net income decreased $144 million to $139by $11 million in the thirdsecond quarter of 20092010, compared to $283 million in the thirdsecond quarter of 2008,2009, primarily due to lower generation-related revenues and decreasedthe absence of deferrals of new regulatory assets, partially offset by lower amortization of regulatory assets and purchased power and other operating expenses.costs.

Revenues

The decrease in total revenues resulted from the following sources:

            
 Three Months    Three Months   
 Ended September 30 Increase  Ended June 30 Increase 
Revenues by Type of Service 2009 2008 (Decrease)  2010 2009 (Decrease) 
 (In millions)  (In millions) 
 
Distribution services
 $915 $1,100 $(185) $851 $813 $38 
       
Generation sales:
        
Retail
 825 986 (161) 1,097 1,514  (417)
Wholesale
  195  286  (91) 180 162 18 
       
Total generation sales
  1,020  1,272  (252) 1,277 1,676  (399)
       
Transmission
 221 241 (20) 200 259  (59)
Other
  47  44  3  64 44 20 
       
Total Revenues
 $2,203 $2,657 $(454) $2,392 $2,792 $(400)
       
The decreaseincrease in distribution deliveries by customer class is summarized in the following table:

Electric Distribution KWH Deliveries   
Residential
  (8.1)7
%
Commercial
  (6.2)5
%
Industrial
  (15.7)13
%
Total Distribution KWH Deliveries
  (9.8)
Total Distribution KWH Deliveries
8%

LowerHigher deliveries to residential and commercial customers reflected decreasedincreased weather-related usage in the thirdsecond quarter of 2009,2010, as cooling degree days decreasedincreased by 14%94% from the same period in 2008.2009. The decreaseincrease in distribution deliveries to commercial and industrial customers was primarily due to recovering economic conditions in FirstEnergy'sFirstEnergy’s service territory.territory compared to the second quarter of 2009. In the industrial sector, KWH deliveries declined dueincreased to major automotive customers (10.1%(39%) and steel customers (42.3%(60%). Transition charges for OE and TE that ceased effective January 1, 2009 withDistribution service revenues increased primarily due to the full recovery of related costs,the PA Energy Efficiency and Conservation charges as approved by the PPUC in March 2010 and the accelerated recovery of deferred distribution costs in Ohio, partially offset by a reduction in the transition rate reduction for CEI effective June 1, 2009, were partially offset by PUCO-approved distribution rate increases (see Regulatory Matters – Ohio).

2009.
The following table summarizes the price and volume factors contributing to the $252$399 million decrease in generation revenues in the thirdsecond quarter of 20092010 compared to the thirdsecond quarter of 2008:2009:

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)

     
  Increase 
Source of Change in Generation Revenues (Decrease) 
  (In millions) 
     
Retail:    
Effect of 29.4% decrease in sales volumes $(444)
Change in prices  27 
    
   (417)
    
     
Wholesale:    
Effect of 10.1% decrease in sales volumes  (16)
Change in prices  34 
    
   18 
    
Decrease in Generation Revenues $(399)
    
The decrease in retail generation sales volumes was primarily due to weakened economic conditions andan increase in customer shopping in the lower weather-related usage described above. The decreaseOhio Companies’ service territories in the second quarter of 2010, which is expected to continue to impact retail generation prices duringsales, partially offset by higher generation revenues related to the thirdrecovery of transmission costs now provided for in the generation rate established under the CBP. Total generation KWH provided by alternative suppliers as a percentage of total KWH deliveries for the Ohio Companies increased to 61% in the second quarter of 20092010, as there was no shopping in the second quarter 2009.

71


The increase in wholesale generation revenues reflected lower composite generation rateshigher prices for JCP&L resulting fromMet-Ed’s and Penelec’s sales of NUG power to the New Jersey BGS auction and for Penn under its RFP process. Wholesale generation salesPJM market.
Transmission revenues decreased principally as a result of JCP&L selling less available power from NUGs$59 million primarily 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 PJMthe Ohio Companies’ transmission revenues partially offset by higher transmission rates for Met-Ed resulting from the annual update to its TSC rider intariff effective June 2009. Met-Ed and Penelec defer the difference between transmission revenues and1, 2009; recovery of transmission costs incurred, resulting in no material effect to current period earnings (see Regulatory Matters – Pennsylvania).is now through the generation rate established under the CBP.

Expenses

Total expenses decreased by $233$393 million due to the net impact of the following:

 ·
Purchased power costs were $237$386 million lower in the thirdsecond quarter of 20092010 due to lower volume requirements, andpartially offset by an increase in unit costs from non-affiliates. The decrease in purchased power volumes from non-affiliates resulted principally from the amounttermination of NUG costs deferred. JCP&L,a third-party supply contract for Met-Ed and Penelec are permittedin January 2010 and from the above described increase in customer shopping in the Ohio Companies’ service territories. The decrease in volumes from FES principally resulted from the increase in customer shopping in the Ohio Companies’ service territories, as described above.
The increase in unit costs from non-affiliates in the second quarter of 2010 resulted from higher capacity prices in the PJM market for Met-Ed and Penelec compared to deferthe second quarter of 2009. The decrease in unit costs from FES was principally due to the lower weighted average unit price per KWH for future collection from customers the amountsOhio Companies established under the CBP auction effective June 1, 2009.
     
  Increase 
Source of Change in Purchased Power (Decrease) 
  (In millions) 
     
Purchases from non-affiliates:    
Change due to increased unit costs $156 
Change due to decreased volumes  (280)
    
   (124)
    
     
Purchases from FES:    
Change due to decreased unit costs  (67)
Change due to decreased volumes  (191)
    
   (258)
    
     
Increase in NUG costs deferred  (4)
    
Net Decrease in Purchased Power Costs $(386)
    
Administrative and general costs, including labor and employee benefit expenses, increased $9 million primarily due to a higher level of incentive compensation earned this year, partially offset by whichlower payroll expenses due to staffing reductions implemented in 2009.
Energy Efficiency program costs incurredincreased $14 million in the second quarter of 2010 compared to the second quarter of 2009.
Forestry contractor costs decreased by $3 million in the second quarter of 2010 compared to the second quarter of 2009, as more resources were dedicated to capital projects in 2010.
A favorable JCP&L labor settlement reduced expenses by $7 million in the second quarter of 2010.
Transmission costs, net of regulatory asset amortization expense, decreased by $61 million primarily due to the transfer of transmission cost responsibility to generation providers under NUG agreements exceed amounts collected through rates. the CBP.
The following table summarizesdeferral of new regulatory assets decreased $45 million in the sourcessecond quarter of changes in2010 principally due to reduced CEI purchased power costs:cost deferrals in the second quarter of 2009.
Depreciation expense increased $5 million due to property additions since the second quarter of 2009.
General taxes decreased $9 million primarily due to a favorable Ohio property tax settlement in 2010.

72



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 thirdsecond quarter of 20092010 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 thirdsecond quarter of 2009 primarily due to lower generationhigher interest expense associated with debt issuances by the Utilities since the second quarter of 2009.
Competitive Energy Services — Second Quarter 2010 Compared with Second Quarter 2009
Net income decreased by $151 million in the second quarter of 2010, compared to the second quarter of 2009, primarily due to the absence of a $252 million gain ($158 million after tax) in 2009 from the sale of a 9% participation interest in OVEC.
Revenues —
Total revenues, excluding the OVEC sale, increased $226 million in the second quarter of 2010 primarily due to an increase in direct and government aggregation sales volumes, partially offset by decreases in POLR sales to the Ohio Companies partially offset by higher non-affiliated retail generation sales volumes.

and wholesale sales.
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
)

             
  Three Months    
  Ended June 30  Increase 
Revenues by Type of Service 2010  2009  (Decrease) 
  (In millions) 
             
Direct and Government Aggregation $586  $83  $503 
POLR  586   839   (253)
Wholesale  95   122   (27)
Transmission  19   16   3 
Sale of OVEC participation interest     252   (252)
Other  31   31    
          
Total Revenues $1,317  $1,343  $(26)
          
The higher retail revenues reflect the acquisition ofincrease in direct and government aggregation programsrevenues of $503 million resulted from increased revenue in Ohioboth the MISO and PJM markets. The increase in revenue primarily resulted from the acquisition of new retail customer contracts in the MISOcommercial and PJM markets in the third quarter of 2009. FES has signedindustrial customers as well as new government aggregation contracts with 50 communities in Ohio that provide discounted generation prices to approximately 600,0001.1 million residential and small commercial customers. Higher non-affiliated wholesale revenues resulted from lower sales volumes and higher prices incustomers at the PJM market offset by lower prices inend of June 2010 compared to 21,000 at the MISO market.

end of June 2009.
The lower affiliated company generationdecrease in POLR revenues wereof $253 million was due primarily to a decrease inlower sales volumes to the Ohio Companies and lower unit prices, partially offset by increased sales volumes and higher unit prices forto the Pennsylvania Companies. The lower sales volumes and unit prices to the Ohio Companies and higher sales volumesin the second quarter 2010 reflected the results of the May 2009 power procurement process. The increased revenues to the Pennsylvania Companies. While unitCompanies resulted from FES supplying Met-Ed and Penelec with volumes previously supplied through a third-party contract and at prices for eachthat were slightly higher than in the second quarter of the Pennsylvania Companies did not change, the mix of2009.
Wholesale revenues decreased $27 million due to reduced volumes, reflecting increased retail sales among the companies caused the composite price to decline. Subsequent to thein 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.

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

     
  Increase 
Source of Change in Direct and Government Aggregation (Decrease) 
  (In millions) 
     
Direct Sales:    
Effect of increase in sales volumes $345 
Change in prices  (16)
    
   329 
    
     
Government Aggregation:    
Effect of increase in sales volumes  174 
Change in prices   
    
   174 
    
Net Increase in Direct and Gov’t Aggregation Revenues $503 
    

73


     
Source of Change in Wholesale Revenues Decrease 
  (In millions) 
     
POLR:    
Effect of 20.4% decrease in sales volumes $(171)
Change in prices  (82)
    
   (253)
    
     
Wholesale:    
Effect of 21.9% decrease in sales volumes  (15)
Change in prices  (12)
    
   (27)
    
     
Decrease in Wholesale Revenues $(280)
    
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 $30increased $3 million duedue primarily to reduced loads following the expiration of the government aggregation programs in Ohio at the end of 2008.higher MISO congestion revenue.

Expenses -

Total expenses decreased $21increased $228 million in the thirdsecond quarter of 20092010 due to the following factors:

following:
· Fuel costs decreased $54increased $75 million due to decreasedincreased generation volumes primarily at the fossil units ($10973 million) and higher unit prices ($2 million). The increase in unit prices was due primarily to higher nuclear fuel unit prices following the refueling outages that occurred in 2009.
Purchased power costs increased $133 million due primarily to higher volumes purchased ($162 million) and higher unit costs ($6 million), partially offset by higher unit pricespower contract mark-to-market adjustments ($5535 million). In July 2010, FES entered into financial transactions that offset the mark-to-market impact of legacy purchased power contracts totaling 500 MW entered into in 2008 for delivery in 2010 and 2011 and which were marked-to-market beginning in December 2009. These financial transactions eliminate the volatility associated with marking these contracts to market through the end of 2011.

· 
Purchased powerFossil operating costs decreased $16$3 million due primarily to lower volume requirements ($71 million),professional and contractor costs, partially offset by higher unit costs ($55 million) resulting from higher capacity costs.reduced gains on the sale of emission allowances.

· 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$17 million due primarily to lower labor and employee benefit expenses of $6 millionprofessional and reductions in contractor costs due to one less refueling outage in 2010 as compared to the same period of $5 million.2009.

· 
Other operatingTransmission expenses increased $32$26 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 costsincreases in MISO of $24$63 million from higher network and higherancillary costs, partially offset by lower PJM transmission expenses of $37 million due to lower congestion and loss costs.
Other expenses increased $14 million primarily due to increases in PJM of $15 million.uncollectible customer accounts and agent fees associated with the growth in direct and government aggregation sales.

       ·
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 thirdsecond quarter of 20092010 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$6 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. Inthan 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$13 million increase in earningsinterest expense from new long-term debt issued combined with the restructuring of existing long-term debt, partially offset by a $7 million increase in investment income resulting from more favorable performance of the nuclear decommissioning trust investments and a decline in interest expense (net($6 million).
Other — Second Quarter of capitalized interest)2010 Compared with Second Quarter 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$13 million decreaseincrease in FirstEnergy's net incomeearnings available to FirstEnergy in the first nine monthsquarter of 20092010 compared to the same period in 2008.2009. The increase resulted primarily from reduced interest expense on holding company debt resulting from the September 2009 tender offer ($20M), partially offset by increased operating expenses.

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Summary of Results of Operations — First Six Months of 2010 Compared with the First Six Months of 2009
Financial results for FirstEnergy’s major business segments in the first six months of 2010 and 2009 were as follows:
                 
  Energy  Competitive  Other and    
  Delivery  Energy  Reconciling  FirstEnergy 
First Six Months 2010 Financial Results Services  Services  Adjustments  Consolidated 
  (In millions) 
Revenues:                
External                
Electric $4,641  $1,397  $  $6,038 
Other  275   97   (50)  322 
Internal*  19   1,213   (1,165)  67 
             
Total Revenues  4,935   2,707   (1,215)  6,427 
             
                 
Expenses:                
Fuel     688   (4)  684 
Purchased power  2,686   769   (1,165)  2,290 
Other operating expenses  732   684   (42)  1,374 
Provision for depreciation  228   132   23   383 
Amortization of regulatory assets  373         373 
Deferral of new regulatory assets            
General taxes  307   60   14   381 
             
Total Expenses  4,326   2,333   (1,174)  5,485 
             
                 
Operating Income  609   374   (41)  942 
             
Other Income (Expense):                
Investment income  52   14   (19)  47 
Interest expense  (248)  (108)  (64)  (420)
Capitalized interest  2   44   35   81 
             
Total Other Expense  (194)  (50)  (48)  (292)
             
                 
Income Before Income Taxes  415   324   (89)  650 
Income taxes  158   123   (36)  245 
             
Net Income (Loss)  257   201   (53)  405 
Noncontrolling interest loss        (15)  (15)
             
Earnings available to FirstEnergy Corp. $257  $201  $(38) $420 
             

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  Energy  Competitive  Other and    
  Delivery  Energy  Reconciling  FirstEnergy 
First Six Months 2009 Financial Results Services  Services  Adjustments  Consolidated 
  (In millions) 
Revenues:                
External                
Electric $5,518  $485  $  $6,003 
Other  295   354   (47)  602 
Internal     1,732   (1,732)   
             
Total Revenues  5,813   2,571   (1,779)  6,605 
             
                 
Expenses:                
Fuel     588      588 
Purchased power  3,553   346   (1,732)  2,167 
Other operating expenses  827   670   (58)  1,439 
Provision for depreciation  219   132   11   362 
Amortization of regulatory assets  642         642 
Deferral of new regulatory assets  (136)        (136)
General taxes  324   57   14   395 
             
Total Expenses  5,429   1,793   (1,765)  5,457 
             
                 
Operating Income  384   778   (14)  1,148 
             
Other Income (Expense):                
Investment income  65   (23)  (26)  16 
Interest expense  (224)  (60)  (116)  (400)
Capitalized interest  2   24   35   61 
             
Total Other Expense  (157)  (59)  (107)  (323)
             
                 
Income Before Income Taxes  227   719   (121)  825 
Income taxes  91   288   (77)  302 
             
Net Income (Loss)  136   431   (44)  523 
Noncontrolling interest loss        (10)  (10)
             
Earnings available to FirstEnergy Corp. $136  $431  $(34) $533 
             

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Changes Between First Six Months 2010 and            
First Six Months 2009 Financial Results            
Increase (Decrease)            
 
Revenues:                
External                
Electric $(877) $912  $  $35 
Other  (20)  (257)  (3)  (280)
Internal*  19   (519)  567   67 
             
Total Revenues  (878)  136   564   (178)
             
                 
Expenses:                
Fuel     100   (4)  96 
Purchased power  (867)  423   567   123 
Other operating expenses  (95)  14   16   (65)
Provision for depreciation  9      12   21 
Amortization of regulatory assets  (269)        (269)
Deferral of new regulatory assets  136         136 
General taxes  (17)  3      (14)
             
Total Expenses  (1,103)  540   591   28 
             
                 
Operating Income  225   (404)  (27)  (206)
             
Other Income (Expense):                
Investment income  (13)  37   7   31 
Interest expense  (24)  (48)  52   (20)
Capitalized interest     20      20 
             
Total Other Expense  (37)  9   59   31 
             
                 
Income Before Income Taxes  188   (395)  32   (175)
Income taxes  67   (165)  41   (57)
             
Net Income (Loss)  121   (230)  (9)  (118)
Noncontrolling interest loss        (5)  (5)
             
Earnings available to FirstEnergy Corp. $121  $(230) $(4) $(113)
             
*Under the accounting standard for the effects of certain types of regulation, internal revenues are not fully offset for sale of RECs by FES to the Ohio Companies that are retained in inventory.
Energy Delivery Services — First Six Months of 2010 Compared to First Six Months of 2009
Net income increased by $121 million in the first six months of 2010, compared to the first six months of 2009, primarily due to the absence of CEI’s $216 million regulatory asset impairment in 2009, lower purchased power costs and lower other operating expenses, partially offset by lower generation related revenues and decreased deferrals of new regulatory assets.
Revenues —
The decrease in total revenues resulted from the following sources:
             
  Six Months    
  Ended June 30  Increase 
Revenues by Type of Service 2010  2009  (Decrease) 
  (In millions) 
Distribution services $1,733  $1,662  $71 
          
Generation sales:            
Retail  2,274   3,128   (854)
Wholesale  397   349   48 
          
Total generation sales  2,671   3,477   (806)
          
Transmission  415   577   (162)
Other  116   97   19 
          
Total Revenues $4,935  $5,813  $(878)
          

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The increase in distribution deliveries by customer class is summarized in the following table:
Electric Distribution KWH Deliveries
Residential1%
Commercial2%
Industrial10%
Total Distribution KWH Deliveries4%
Higher deliveries to residential and commercial customers reflected increased weather-related usage in the first six months of 2010. Cooling degree days increased by 94%, partially offset by a 10% decrease in heating degree days from the same period in 2009. The increase in distribution deliveries to industrial customers was primarily due to recovering economic conditions in FirstEnergy’s service territory compared to the first six months of 2009. In the industrial sector, KWH deliveries increased to major automotive customers (26%) and steel customers (44%). Distribution service revenues increased primarily due to the recovery of the PA Energy Efficiency and Conservation charges as approved by the PPUC in March 2010 and the accelerated recovery of deferred distribution costs in Ohio, partially offset by a reduction in the transition rate for CEI effective June 1, 2009.
The following table summarizes the price and volume factors contributing to the $806 million decrease in generation revenues in the first six months of 2010 compared to the same period of 2009:
     
  Increase 
Source of Change in Generation Revenues (Decrease) 
  (In millions) 
Retail:    
Effect of 30% decrease in sales volumes $(939)
Change in prices  85 
    
   (854)
    
     
Wholesale:    
Effect of 12.2% decrease in sales volumes  (42)
Change in prices  90 
    
   48 
    
Net Decrease in Generation Revenues $(806)
    
The decrease in retail generation sales volumes was primarily due to an increase in customer shopping in the Ohio Companies’ service territories in the first six months of 2010, which is expected to continue to impact retail generation sales, partially offset by higher generation revenues related to the recovery of transmission costs now provided for in the generation rate established under the CBP. Total generation KWH provided by alternative suppliers as a percentage of total KWH deliveries for the Ohio Companies increased to 57% in the first six months of 2010, as there was no shopping in the same period of 2009.
The increase in wholesale generation revenues reflected higher prices for Met-Ed’s and Penelec’s NUG sales to the PJM market.
Transmission revenues decreased $162 million primarily due to the termination of the Ohio Companies’ transmission tariff effective June 1, 2009; recovery of transmission costs is now through the generation rate established under the CBP.
Expenses —
Total expenses decreased by $1,103 million due to the following:
Purchased power costs were $867 million lower in the first six months of 2010 due to lower volume requirements, partially offset by an increase in unit costs for purchased power from non-affiliates. The decrease in volumes from non-affiliates resulted principally from the termination of a third-party supply contract for Met-Ed and Penelec in January 2010 and from the above described increase in customer shopping in the Ohio Companies’ service territories. The decrease in volumes from FES principally resulted from the increase in customer shopping in the Ohio Companies’ service territories, as described above.
The increase in unit costs from non-affiliates in the first six months of 2010 resulted from higher capacity prices in the PJM market for Met-Ed and Penelec compared to the first six months of 2009. The decrease in unit costs from FES was principally due to the lower weighted average unit price per KWH for the Ohio Companies established under the CBP auction effective June 1, 2009.

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  Increase 
Source of Change in Purchased Power (Decrease) 
  (In millions) 
Purchases from non-affiliates:    
Change due to increased unit costs $346 
Change due to decreased volumes  (703)
    
   (357)
    
     
Purchases from FES:    
Change due to decreased unit costs  (160)
Change due to decreased volumes  (343)
    
   (503)
    
     
Increase in NUG costs deferred  (7)
    
Net Decrease in Purchased Power Costs $(867)
    
MISO/PJM transmission expenses decreased $43 million primarily due to the recovery of transmission costs now provided for in the generation rate established under the CBP, partially offset by higher PJM congestion charges.
Administrative and general costs, including labor and employee benefits expenses, decreased by $22 million in the first six month of 2010 compared to 2009 due to lower payroll expenses resulting from staffing reductions implemented in 2009.
Other operating expenses decreased $28 million due to higher economic development commitments recognized in the first quarter of 2009 relating to the amended ESP and a favorable labor settlement of $7 million for JCP&L recognized in the second quarter of 2010.
Amortization of regulatory assets decreased $269 million due primarily to the absence of the $216 million impairment of CEI’s regulatory assets in the second quarter of 2009, reduced transmission cost amortization and reduced CTC amortization for Met-Ed and Penelec, partially offset by a $35 million regulatory asset impairment associated with the filing of the Ohio Companies’ ESP on March 23, 2010.
The deferral of new regulatory assets decreased $136 million in the first six months of 2010 principally due to reduced CEI purchased power cost deferrals in the second quarter of 2009.
Depreciation expense increased $9 million due to property additions since the second quarter of 2009.
General taxes decreased $17 million due to favorable Ohio and Pennsylvania tax settlements in 2010.
Other Expense —
Other expense increased $37 million in the first six months of 2010 compared to the first six months of 2009 primarily due to higher interest expense associated with debt issuances by the Utilities since the second quarter of 2009.
Competitive Energy Services — First Six Months of 2010 Compared to First Six Months of 2009
Net income decreased by $230 million in the first six months of 2010, compared to the first six months of 2009, primarily due to the absence of a $252 million ($158 million after tax) gain in 2009 from the sale of a 9% participation in OVEC and a decrease in sales margins.
Revenues —
Total revenues, excluding the OVEC sale, increased $388 million in the first six months of 2010 compared to the same period in 2009 primarily due to an increase in direct and government aggregation sales volumes and sales of RECs, partially offset by decreases in POLR sales to the Ohio Companies and wholesale sales.

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The increase in reported segment revenues resulted from the following sources:
             
  Six Months    
  Ended June 30  Increase 
Revenues by Type of Service 2010  2009  (Decrease) 
  (In millions) 
Direct and Government Aggregation $1,097  $174  $923 
POLR  1,260   1,732   (472)
Wholesale  186   311   (125)
Transmission  36   41   (5)
RECs  67      67 
Sale of OVEC participation interest     252   (252)
Other  61   61    
          
Total Revenues $2,707  $2,571  $136 
          
The increase in direct and government aggregation revenues of $923 million resulted from increased revenue in both the MISO and PJM markets. The increase in revenue primarily resulted from the acquisition of new commercial and industrial customers, as well as new government aggregation contracts with communities in Ohio that provide generation to 1.1 million residential and small commercial customers at the end of June 2010 compared to 21,000 at the end of June 2009, partially offset by lower unit prices. During January 2010, FES began supplying power to approximately 425,000 NOPEC customers.
The decrease in POLR revenues of $472 million was due to lower sales volumes to the Ohio Companies and lower unit prices, partially offset by increased sales volumes and higher unit prices to the Pennsylvania Companies. The lower sales volumes and unit prices to the Ohio Companies in 2010 reflected the results of the May 2009 power procurement process. The increased revenues to the Pennsylvania Companies resulted from FES supplying Met-Ed and Penelec with volumes previously supplied through a third-party contract and at prices that were slightly higher than in 2009.
Wholesale revenues decreased $125 million due to reduced volumes reflecting market declines and lower prices.
The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:
     
  Increase 
Source of Change in Direct and Government Aggregation (Decrease) 
  (In millions) 
Direct Sales:    
Effect of increase in sales volumes $633 
Change in prices  (47)
    
   586 
    
     
Government Aggregation:    
Effect of increase in sales volumes  337 
Change in prices   
    
   337 
    
Net Increase in Direct and Gov’t Aggregation Revenues $923 
    
     
Source of Change in Wholesale Revenues Decrease 
  (In millions) 
POLR:    
Effect of 15.1% decrease in sales volumes $(262)
Change in prices  (210)
    
   (472)
    
     
Wholesale:    
Effect of 56.7% decrease in sales volumes  (123)
Change in prices  (2)
    
   (125)
    
Decrease in Wholesale Revenues $(597)
    
Transmission revenues decreased $5 million due primarily to lower PJM congestion revenue.

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Expenses —
Total expenses increased $540 million in the first six months of 2010 due to the following factors:
Fuel costs increased $100 million due to increased generation volumes ($44 million) and higher unit prices ($56 million). The increase in unit prices was due primarily to higher nuclear fuel unit prices following the refueling outages that occurred in 2009 and increased coal transportation costs.
Purchased power costs increased $423 million due primarily to higher volumes purchased ($484 million), and power contract mark-to-market adjustments ($17 million), partially offset by lower unit costs ($78 million). In July 2010, FES entered into financial transactions that offset the mark-to-market impact of legacy purchased power contracts totaling 500 MW entered into in 2008 for delivery in 2010 and 2011 and which were marked-to-market beginning in December 2009. These financial transactions eliminate the volatility associated with marking these contracts to market through the end of 2011.
Fossil operating costs decreased $2 million due primarily to lower labor costs which were partially offset by higher professional and contractor costs and reduced gains on the sale of emission allowances.
Nuclear operating costs decreased $37 million due primarily to lower labor and professional and contractor costs. The six months ended June 2010 had one less refueling outage and fewer extended outages than the same period of 2009.
Transmission expenses increased $33 million due primarily to increased costs in MISO of $106 million from higher network and ancillary costs, partially offset by lower PJM transmission expenses of $73 million due to lower congestion and loss costs.
Other expenses increased $20 million primarily due to increases in uncollectible customer accounts and agent fees associated with the growth in direct and government aggregation sales.
General taxes increased $3 million due to sales taxes on higher revenues.
Other Expense —
Total other expense in the six months ending June 2010 was $9 million lower than the same period in 2009, primarily due to a $37 million increase in investment income resulting from more favorable performance of the nuclear decommissioning trust investments, partially offset by a $28 million increase in interest expense. Interest expense increased because of new issuances of long-term debt combined with the restructuring of existing long-term debt.
Other — First Six Months of 2010 Compared to First Six Months of 2009
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 $4 million decrease in earnings available to FirstEnergy in the first six months of 2010 compared to the same period in 2009. The decrease resulted primarily from increased other operating expenses and depreciation ($28 million) and increased income tax expense ($41 million), partially offset by reduced interest expense on holding company debt redemption costs ($90 million, net52 million) which was primarily the result of taxes) and  the absence of the gain on the 2008 sale of telecommunication assets ($19 million, net of taxes).
a September 2009 tender offer.
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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'sFirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. During 20092010 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.

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As of SeptemberJune 30, 2009, FirstEnergy's2010, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was principally due to short-term borrowings ($1.71.5 billion) and the classification of certain variable interest rate PCRBs as currently payable long-term debt. Currently payable long-term debt as of SeptemberJune 30, 2009,2010, included the following (in millions):

     
Currently Payable Long-term Debt    
PCRBs supported by bank LOCs (1)
 $1,318 
FGCO and NGC unsecured PCRBs (1)
  75 
Penelec FMBs (2)
  24 
NGC collateralized lease obligation bonds
  50 
Sinking fund requirements
  41 
Other notes (2)
  63 
    
  $1,571 
    
(1)Interest rate mode permits individual debt holders to put the respective debt back to the issuer prior to maturity.
(2)Mature in November 2010.

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$1.5 billion of short-term borrowings as of SeptemberJune 30, 20092010 and $2.4$1.2 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's2009. FirstEnergy’s available liquidity as of October 30, 2009,July 31, 2010, is summarized in the following table:

                 
              Available 
Company Type Maturity  Commitment  Liquidity 
          (In millions) 
FirstEnergy(1)
 Revolving Aug. 2012  $2,750  $1,407 
FirstEnergy Solutions Bank line Mar. 2011   100    
Ohio and Pennsylvania Companies Receivables financing Various(2)  395   267 
               
      Subtotal  $3,245  $1,674 
      Cash      127 
               
      Total  $3,245  $1,801 
               
(1)FirstEnergy Corp. and subsidiary borrowers.
(2)Ohio — $250 million matures March 30, 2011; Pennsylvania — $145 million matures December 17, 2010
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. A total of 25 banks participate in the facility, with no one bank having more than 7.3% of the total commitment. 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.

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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 SeptemberJune 30, 2009:2010:

         
  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   34(2)
CEI  250(3)  500 
TE  250(3)  500 
JCP&L  425   405(2)
Met-Ed  250   300(2)
Penelec  250   300(2)
ATSI  50(4)  50 
  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.
 

(1)No regulatory approvals, statutory or charter limitations applicable.
(2)Excluding amounts that 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 ATSI has received regulatory approval to have short-term borrowings up to the same amount.
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'sborrower’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 SeptemberJune 30, 2009, FirstEnergy's2010, FirstEnergy’s and its subsidiaries'subsidiaries’ debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:

Borrower  
FirstEnergy(1)
 61.661.1%
FES
 54.252.1%
OE
 46.653.4%
Penn
 32.931.3%
CEI
 59.3%
TE
 53.959.1%
JCP&L
 34.936.5%
Met-Ed
 41.638.2%
Penelec
 54.153.4%
ATSI
50.3%

 (1)
(1)As of SeptemberJune 30, 2009,2010, FirstEnergy could issue additional debt of approximately $2.4$2.9 billion, or recognize a reduction in equity of approximately $1.3$1.6 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“pricing grids," whereby the cost of funds borrowed under the facility is related to the credit ratings of the company borrowing the funds.

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FirstEnergy Money Pools

FirstEnergy'sFirstEnergy’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'sFirstEnergy’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 ninesix months of 20092010 was 0.78%0.51% per annum for the regulated companies'companies’ money pool and 0.96%0.59% per annum for the unregulated companies'companies’ money pool.

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Pollution Control Revenue Bonds

As of SeptemberJune 30, 2009, FirstEnergy's2010, FirstEnergy’s currently payable long-term debt included approximately $1.6$1.3 billion (FES - $1.5— $1.2 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:banks as of June 30, 2010:

         
  Aggregate LOC    Reimbursements of
LOC Bank Amount(2)  LOC Termination Date LOC Draws Due
  (In millions)     
CitiBank N.A. $166  June 2014 June 2014
The Bank of Nova Scotia  284  Beginning April 2011 Multiple dates(3)
The Royal Bank of Scotland  131  June 2012 6 months
Wachovia Bank  153  March 2014 March 2014
Barclays Bank(1)
  528  Beginning December 2010 30 days
PNC Bank  70  Beginning November 2010 180 days
        
Total $1,332     
        
  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.

(1)Supported by 18 participating banks, with no one bank having more than 14% of the total commitment.
(2)Includes approximately $14 million of applicable interest coverage.
(3)Shorter of 6 months or LOC termination date ($155 million) and shorter of one year or LOC termination date ($129 million).
In February 2009, holders of approximately $434June 2010, FGCO purchased $15 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 wereoriginally issued and sold on behalf ofits behalf. In April 2010, 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 repurchasedpurchased approximately $52.1$235 million and $29.6 million of variable rate PCRBs respectively. These PCRBs are secured by a corresponding series of FMBs until December 31, 2009.and cancelled $237 million LOC held with KeyBank. Subject to market conditions, FGCO and NGC planplans to remarket the $15 million PCRBs, as well as the $235 million PCRBs purchased PCRBs in fixed-rate modeApril, in the near future.future as market conditions permit.


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Long-Term Debt Capacity

As of SeptemberJune 30, 2009,2010, the Ohio Companies and Penn had the aggregate capability to issue approximately $1.5$2.3 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$107 million and $32$21 million, respectively, as of SeptemberJune 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 2006.2010. As a result of the indenture provisions, for TE tocannot incur any additional secured debt. Met-Ed and Penelec had the capability to issue secured debt do not apply. In August 2009 CEI issued $300of approximately $377 million and $343 million, respectively, under provisions of FMB. CEI restricted $150 milliontheir senior note indentures as of the proceeds to fund the redemption of $150 million of secured notes due in November 2009.

June 30, 2010.
Based upon FGCO'sFGCO’s FMB indenture, net earnings and available bondable property additions as of SeptemberJune 30, 2009,2010, FGCO had the capability to issue $2.2$2.9 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$294 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.2010.

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'sFirstEnergy’s access to capital markets and costs of financing are influenced by the ratings of its securities. On February 11, 2010, S&P issued a report lowering FirstEnergy’s and its subsidiaries credit ratings by one notch, while maintaining its stable outlook. Moody’s and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries on February 11, 2010. The following table displays FirstEnergy's, FES'FirstEnergy’s, FES’ and the Utilities'Utilities’ securities ratings as of SeptemberJune 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."2010.

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Issuer  Securities 
Senior SecuredSenior Unsecured
Issuer S&P Moody’sMoody'sFitchS&PMoody’sFitch
FirstEnergy Corp.BB+Baa3BBB
       
FirstEnergy Solutions Senior unsecured BBB- Baa3Baa2BBB
       
FES Senior secured
Ohio Edison BBB Baa1
A3 Senior unsecuredBBB+BBB-Baa2 BBBBaa2
       
OE Senior secured
Pennsylvania Power BBB+ A3
 BBB+ Senior unsecured BBB Baa2
       
Penn Senior secured A-
Cleveland Electric Illuminating A3BBBBaa1BBBBBB-Baa3BBB-
       
CEISenior securedBBB+Baa1
  Senior unsecured
Toledo Edison BBB Baa3Baa1BBB
       
TESenior securedBBB+Baa1
  Senior unsecured BBB
Jersey Central Power & Light Baa3BBB-Baa2BBB+
       
JCP&L Senior unsecured
Metropolitan Edison BBB A3BBB+BBB-Baa2BBB
       
Met-Ed Senior unsecured
Pennsylvania Electric BBB A3BBB+BBB-Baa2BBB
       
Penelec Senior unsecured BBB
ATSI Baa2BBB-Baa1

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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 SeptemberJune 30, 2009,2010, FirstEnergy had $838$281 million in cash and cash equivalents compared to $545$874 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.2009. As of SeptemberJune 30, 2009, approximately $794 million of cash and cash equivalents represented temporary overnight deposits. As of September 30, 20092010 and December 31, 2008,2009, FirstEnergy had $171approximately $10 million and $17$12 million, respectively, of restricted cash included in other current assets on the Consolidated Balance Sheet.

During the first ninesix months of 2009,2010, FirstEnergy received $621$655 million of cash from dividends and equity repurchases from its subsidiaries and paid $503$335 million in cash dividends to common shareholders. With the exception of Met-Ed, which is currently in an accumulated deficit position, there are no material restrictions on the payment of cash dividends by 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'sFirstEnergy’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 increaseddecreased by $33$244 million during the first ninesix months of 20092010 compared to the comparable period in 2008,2009, as summarized in the following table:

            
 Six Months   
 
Nine Months Ended
September 30
     Ended June 30 Increase 
Operating Cash Flows
 2009 2008 Increase (Decrease)  2010 2009 (Decrease) 
 (In millions)  (In millions) 
Net income $754 $1,011 $(257) $405 $523 $(118)
Non-cash charges and other adjustments  1,755  1,033  722  789 719 70 
Pension trust contribution  (500)  -  (500)
Working capital and other  (545)  (613) 68 
Working Capital and other  (336)  (140)  (196)
 $1,464 $1,431 $33        
 $858 $1,102 $(244)
       
The increase in non-cash charges and other adjustments is primarily due to higher deferred income taxes and investment tax credits ($90 million) and higher non-cash retirement benefit expenses ($66 million) recognized in the first six months of 2010, partially offset by lower net amortization of regulatory assets ($233133 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 inrecorded during 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,first quarter of which $122 million was related primarily to the premium paid and included as a cash outflow in financing activities.2009. The changeschange in working capital and other charges primarily resulted from a $73$111 million decrease in stock-based compensation paymentscash collateral received, a $98 million decrease in prepayments and another current assets, and a $43 million increase in other accrued expenses principally associated withtaxes, partially offset by a $188 million increase in receivables and a $23 million increase in materials and supplies. The change in prepayments and accrued taxes primarily relates to the implementationtiming of the Ohio Companies’ Amended ESP.income tax payments.

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Cash Flows From Financing Activities

In the first ninesix months of 2009,2010, cash used for financing activities was $484 million compared to cash provided from financing activities was $617 million compared to $911of $426 million in the first ninesix months of 2008.2009. The decrease was primarily due to increasednew debt issuances in 2009 and the repayment of short-term borrowings in 2010, partially offset by decreased 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.2010. 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.redemptions:

         
  Six Months 
  Ended June 30 
Securities Issued or Redeemed 2010  2009 
  (In millions) 
         
New Issues
        
First mortgage bonds     100 
Pollution control notes     682 
Senior secured notes     297 
Unsecured Notes     600 
       
  $  $1,679 
       
         
Redemptions
        
Pollution control notes  251   682 
Senior secured notes  55   46 
Unsecured notes  100   153 
       
  $406  $881 
       
         
Short-term borrowings, net $281  $ 
       
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  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 ninefirst six months ended September 30,of 2010 and 2009 and 2008 by business segment:

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Summary of Cash Flows Property        Property       
Provided from (Used for) Investing Activities Additions Investments Other Total  Additions Investments Other Total 
 (In millions) 
Sources (Uses) (In millions)  
Nine Months Ended September 30, 2009         
Six Months Ended June 30, 2010
 
Energy delivery services
 
$
(524
)
$
(121)
$
(35)
$
(680
)
 $(338) $87 $(20) $(271)
Competitive energy services
 (893
)
 (6
)
 (21) (920
)
  (605)  (11)  (1)  (617)
Other
 (133
)
 - (11
)
 (144
)
  (10)  (3)   (13)
Inter-Segment reconciling items
  (25
)
 (25) 6  (44
)
  (44)  (22)   (66)
         
Total
 
$
(1,575
)
$
(152)
$
(61
)
$
(1,788
)
 $(997) $51 $(21) $(967)
                   
Nine Months Ended September 30, 2008
          
 
Six Months Ended June 30, 2009
 
Energy delivery services
 $(621)$33 $(3)$(591) $(343) $48 $(23) $(318)
Competitive energy services
 (1,430) (13) (121) (1,564)  (669) 2  (22)  (689)
Other
 (106) 57 (54) (103)  (119)  (7)  (3)  (129)
Inter-Segment reconciling items
  (20) (12) -  (32)  (12)  (25)   (37)
         
Total
 $(2,177)$65 $(178)$(2,290) $(1,143) $18 $(48) $(1,173)
         
Net cash used for investing activities in the first ninesix months of 20092010 decreased by $502$206 million compared to the first ninesix months of 2008.2009. The decrease was principally due to a $602$146 million decrease in property additions, which reflects lower AQC system expenditures, and the absence in 2009cash proceeds 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 proceedsapproximately $116 million from the sale of telecommunication assets, inpartially offset by $105 million relating to the first quarteracquisition of 2008 combined with increased restricted funds to be used for future debt redemptions.customer intangible assets.

During the last three monthsremaining two quarters of 2009,2010, capital requirements for property additions and capital leases are expected to be approximately $410$918 million, including approximately $65$155 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 and short-term credit arrangements and funds raised in the capital markets.
arrangements.
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’seither FirstEnergy or its subsidiaries’ credit ratings.

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As of SeptemberJune 30, 2009,2010, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.1$3.9 billion, as summarized below:

     
  Maximum 
Guarantees and Other Assurances Exposure 
  (In millions) 
FirstEnergy Guarantees on Behalf of its Subsidiaries    
Energy and Energy-Related Contracts(1)
 $300 
LOC (long-term debt) —Interest coverage(2)
  6 
FirstEnergy guarantee of OVEC obligations  300 
Other(3)
  294 
    
   900 
    
     
Subsidiaries’ Guarantees    
Energy and Energy-Related Contracts  54 
LOC (long-term debt) —Interest coverage(2)
  4 
FES’ guarantee of NGC’s nuclear property insurance  70 
FES’ guarantee of FGCO’s sale and leaseback obligations  2,413 
Other  2 
    
   2,543 
    
     
Surety Bonds  90 
LOC (long-term debt) — Interest coverage(2)
  3 
LOC (non-debt)(4)(5)
  372 
    
   465 
    
Total Guarantees and Other Assurances $3,908 
    
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  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 $1.3 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, which has been reduced to $15 million in July 2010, and $161 million supporting OE’s sale
and leaseback arrangement.
 
(4)
Includes $58$193 million issued for various terms pursuant to LOC capacity available
under FirstEnergy’s revolving credit facility.
 
(5)
Includes approximately $206$135 million pledged in connection with the sale and l
easebackleaseback of Beaver Valley Unit 2 by OE and $134$44 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'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'scounterparty’s legal claim to be satisfied by FirstEnergyFirstEnergy’s 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.

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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, an acceleration or funding obligation, or a “material adverse event,” the immediate posting of cash collateral, provision of ana LOC or accelerated payments may be required of the subsidiary. As of SeptemberJune 30, 2009,2010, FirstEnergy’s maximum exposure under these collateral provisions was $616$451 million, as shown below:

            
Collateral Provisions FES Utilities Total  FES Utilities Total 
 (In millions)  (In millions) 
Credit rating downgrade to below investment grade $305 $115 $420  $314 $17 $331 
Acceleration of payment or funding obligation  80 63 143  15 68 83 
Material adverse event  53  -  53  37  37 
       
Total $438 $178 $616  $366 $85 $451 
       
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$609 million, consisting of $60$56 million due to “material adverse event” contractual clauses, $83 million due to an acceleration of payment or funding obligation, and $639$470 million due to a below investment grade credit rating.

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Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $90 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’ power portfolio as of SeptemberJune 30, 2009,2010, and forward prices as of that date, FES had $183 millionhas posted collateral of outstanding collateral payments.$245 million. Under a hypothetical adverse change in forward prices (15% decrease(95% confidence level change in the first 12 months and 20% decrease thereafter in prices)forward prices over a one year time horizon), FES would be required to post an additional $45$107 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 thean 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 toand FES 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$1.6 billion as of SeptemberJune 30, 2009.2010.

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'sFirstEnergy’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 --associated with 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:

88


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 53 to the consolidated financial statements). Sources of information for the valuation of commodity derivative contracts as of SeptemberJune 30, 20092010 are summarized by year in the following table:

                             
Source of Information-                     
Fair Value by Contract Year 2010  2011  2012  2013  2014  Thereafter  Total 
  (In millions) 
Prices actively quoted(1)
 $(5) $  $  $  $  $  $(5)
Other external sources(2)
  (322)  (332)  (147)  (34)  4   (17)  (848)
Prices based on models              (9)  138   129 
                      
Total(3)
 $(327) $(332) $(147) $(34) $(5) $121  $(724)
                      
(1)Represents exchange traded NYMEX futures and options.
(2)Primarily represents contracts based on broker and ICE quotes.
(3)Includes $547 million in non-hedge commodity derivative contracts that are primarily related to NUG contracts. NUG contracts are subject to regulatory accounting and do not impact earnings.
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 SeptemberJune 30, 2009,2010, an adverse 10% change in commodity prices would decrease net income by approximately $4$9 million ($6 million net of tax) during the next 12 months.

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Forward StartingInterest Rate Swap Agreements - Cash Flow— Fair Value Hedges

FirstEnergy uses forward startingfixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with issuances of fixed-rate, long-termthe debt securitiesportfolio of its subsidiaries. These derivatives are treated as cash flowfair value hedges of fixed-rate, long-term debt issues, protecting against the risk of changes in futurethe fair value of fixed-rate debt instruments due to lower interest payments resulting from changes in benchmark U.S. Treasury rates between the daterates. In May of hedge inception and the date of the debt issuance. For the three months and nine months ended September 30, 2009,2010, FirstEnergy terminated forward swapsfixed-for-floating interest rate swap agreements with a notional value of $2.3$3.15 billion, and $2.4 billion, respectively. FirstEnergy recognized losseswhich resulted in cash proceeds 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$43.1 million. These proceeds will be amortized to interest expenseearnings over the life of the hedgedunderlying debt.

Effective June 1, 2010, FirstEnergy executed multiple fixed-for-floating interest rate swap agreements with a combined notional value of $3.2 billion, which essentially replaced the swap agreements terminated in May of 2010. As of June 30, 2010, the debt underlying the $3.2 billion outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 6%, which the swaps have converted to a current weighted average variable rate of 4%. A hypothetical 10% increase in the interest rates associated with variable-rate debt would decrease net income by less than $1 million for the three and six months ended June 30, 2010.
  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
)
On July 16, 2010, FirstEnergy terminated these fixed-for-floating interest rate swap agreements with a notional value of $3.2 billion, which resulted in cash proceeds of $83.6 million. These proceeds will be amortized to earnings over the life of the underlying debt. While FirstEnergy currently does not have any interest rate swaps outstanding, costs associated with entering into future swap transactions may be increased as a result of the recent passage of the Dodd-Frank Wall Street Reform and Consumer Protection Act, which requires increased regulation of swaps, swap dealers and major swap participants.

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 remeasureddate or 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.significant triggering events occur. As of December 31, 2008,June 30, 2010, approximately 53% of the pension plan was underfundedis invested in equity securities and it remained underfunded after47% is invested in fixed income securities and the voluntary contribution and remeasurement on August 31, 2009.plan is currently underfunded. A decline in the value of FirstEnergy’s pension plans could result in additional funding requirements. FirstEnergy currently estimates that additional cash contributions will be required beginning in 2014 for the 2013 plan year.2012. The overall actual investment result during 2009 was a gain of 13.6% compared to an assumed 9% positive return.

89



Nuclear decommissioning trust funds have been established to satisfy NGC'sNGC’s and the Utilities'Utilities’ nuclear decommissioning obligations. As of SeptemberJune 30, 2009,2010, approximately 15% of the funds were invested in equity securities and 85% 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$275 million as of SeptemberJune 30, 2009.2010. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $28 million reduction in fair value as of SeptemberJune 30, 2009.2010. 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 foras 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) existedA decline in the value of FirstEnergy’s nuclear decommissioning trusts could result in additional funding requirements. As of June 30, 2010, $4 million was contributed to the OE and TE nuclear decommissioning trusts to comply with requirements under certain sale-leaseback transactions in which OE and TE continue as lessees, and $3 million was contributed to the JCP&L and Pennsylvania nuclear decommissioning trusts to comply with regulatory requirements. FirstEnergy continues to evaluate the status of its funding obligations for the decommissioning trust fund for Beaver Valley Unit 1. On November 5, 2009,of these nuclear facilities and does not expect to make additional cash contributions to 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 licensestrusts for the Beaver Valley Power Station in 2009. FENOC continuesremainder of 2010 other than those to communicate with the NRC regarding future actionsJCP&L and Pennsylvania Companies’ nuclear decommissioning trusts due to provide reasonable assurance for decommissioning funding. Such actions may include additional parental guarantees or contributions to those funds.
regulatory requirements.
102



CREDIT RISK

Credit risk is the risk of an obligor'sobligor’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 engageFirstEnergy engages in transactions for the purchase and sale of commodities including gas, electricity, coal and emission allowances. These transactions are often with major energy companies within the industry.

We maintainFirstEnergy maintains credit policies with respect to ourits 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 ourits credit program, weFirstEnergy aggressively managemanages the quality of ourits portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As of SeptemberJune 30, 2009,2010, the largest credit concentration was with JP Morgan,AEP, which is currently rated investment grade, representing 10.7%7.85% of ourFirstEnergy’s total approved credit risk.

OUTLOOK

State Regulatory Matters

In Ohio, New JerseyFirstEnergy and Pennsylvania, laws applicable to electric industry restructuring contain similar provisions that are reflectedthe utilities prepare their consolidated financial statements in accordance with 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, asauthoritative guidance for accounting for certain types of regulation. Under this guidance, regulatory assets represent incurred or accrued costs which the FERC, the PUCO, the PPUC and the NJBPUthat have authorized forbeen deferred because of their probable future recovery from customers inthrough regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future periods or for which authorization is probable. Withoutregulated rates. The following table provides the probabilitybalance of such authorization, costs currently recorded as regulatory assets would have been charged to incomeby Company as incurred. of June 30, 2010 and December 31, 2009, and changes during the six months then ended:
             
  June 30,  December 31,  Increase 
Regulatory Assets 2010  2009  (Decrease) 
  (In millions) 
OE $423  $465  $(42)
CEI  468   546   (78)
TE  82   70   12 
JCP&L  801   888   (87)
Met-Ed  385   357   28 
Penelec  139   9   130 
Other  15   21   (6)
          
Total $2,313  $2,356  $(43)
          

90


The following table provides information about the composition of regulatory assets as of June 30, 2010 and December 31, 2009 and the changes during the six months then ended:
             
  June 30,  December 31,  Increase 
Regulatory Assets by Source 2010  2009  (Decrease) 
  (In millions) 
Regulatory transition costs $1,153  $1,100  $53 
Customer shopping incentives  74   154   (80)
Customer receivables for future income taxes  332   329   3 
Loss on reacquired debt  49   51   (2)
Employee postretirement benefits  19   23   (4)
Nuclear decommissioning, decontamination and spent fuel disposal costs  (152)  (162)  10 
Asset removal costs  (235)  (231)  (4)
MISO/PJM transmission costs  156   148   8 
Fuel costs  385   369   16 
Distribution costs  408   482   (74)
Other  124   93   31 
          
Total $2,313  $2,356  $(43)
          
Regulatory assets that do not earn a current return totaled approximately $172$181 million as of SeptemberJune 30, 20092010 (JCP&L - $42— $43 million, Met-Ed - $102— $131 million, Penelec — $3 million and Penelec - $28CEI $4 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. TheFederally-enforceable 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 responsibilitiesthese reliability standards to eight regional entities, including ReliabilityFirstCorporation. All of FirstEnergy’s facilities are located within the ReliabilityFirstregion. FirstEnergy actively participates in the NERC and ReliabilityFirststakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards.standards implemented and enforced by the ReliabilityFirstCorporation.

FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, it is clearFirstEnergy also believes that the NERC, ReliabilityFirstand 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, thetime; however, 2005 amendments to the Federal Power ActFPA 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 thusthat could 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 withresulting in customers in the affected area losing power. Power was restoredpower for up 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 requiredNERC has submitted first and second Requests for Information regarding this and another related matter. 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 interviewsis complying 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.these requests. JCP&L is not able at this time to predict what actions, if any, that the NERC may take basedwith respect to this matter.
Ohio
The Ohio Companies operate under an Amended ESP, which expires on the data submittals or interview results.

On June 5, 2009, FirstEnergy self-reported to ReliabilityFirstMay 31, 2011, and provides for generation supplied through 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.CBP. 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,Amended ESP also allows 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 (Rider DSI) at an overall average rate of $.002$0.002 per KWH for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addressedOhio Companies currently purchase generation at the average wholesale rate of a number of other issues, including but not limited to, rate design for various customer classes, and resolutionCBP conducted in May 2009. FES is one of the prudence review and the collection of deferred costs that were approved in prior proceedings. On February 26, 2009,suppliers to the Ohio Companies filed a Supplemental Stipulation, which was signed or not opposed by virtually all ofthrough 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.CBP. 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,a $136.6 million distribution rate increase for the Ohio Companies filed applications within January 2009, which went into effect on January 23, 2009 for OE ($68.9 million) and TE ($38.5 million) and on May 1, 2009 for CEI ($29.2 million). As one element of the PUCO to recover three different categories of deferred distribution costs on an accelerated basis. In the Ohio Companies' Amended ESP, the Ohio Companies agreed not to seek an additional base distribution rate increase, subject to certain exceptions, that would be effective before January 1, 2012. Applications for rehearing of the PUCO approvedorder in 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 applicationsdistribution case were approvedfiled 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.party. The Ohio Companies askedraised numerous issues in their application for rehearing related to rate recovery of certain expenses, recovery of line extension costs, the Commission to issuelevel of rate of return and the amount of general plant balances. The PUCO has not yet issued a rulingsubstantive Entry on or before December 2, 2009.Rehearing.

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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 establishthrough a CBP, to secure generation supply for customers who do not shop with an alternative supplier andfor the period beginning June 1, 2011. The CBP 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 reduceand supplier risk and encourage bidder participation. A technical conference wasand hearings were held on October 29,in 2009 atand the PUCO.matter has been fully briefed. Pursuant to SB221, the PUCO has 90 days from the date of the application to determine whether the MRO meets certain statutory requirements, therefore,requirements. Although the Ohio Companies have requested a PUCO determination by January 18, 2010.2010, on February 3, 2010, the PUCO announced that its determination would be delayed. Under a determination that such statutory requirements wereare met, and to the extent the ESP described below has not been implemented, the Ohio Companies would be ableexpect to implement the MRO.
On March 23, 2010, the Ohio Companies filed an application for a new ESP, which if approved by the PUCO, would go into effect on June 1, 2011 and conclude on May 31, 2014. Attached to the application was a Stipulation and Recommendation signed by the Ohio Companies, the Staff of the PUCO, and an additional fourteen parties signing as Signatory Parties, with two additional parties agreeing not to oppose the adoption of the Stipulation. The material terms of the Stipulation include a CBP similar to the one used in May 2009 and the one proposed in the October 2009 MRO filing; a 6% generation discount to certain low-income customers provided by the Ohio Companies through a bilateral wholesale contract with FES; no increase in base distribution rates through May 31, 2014; and a new distribution rider, Delivery Capital Recovery Rider (Rider DCR), to recover a return of, and on, capital investments in the delivery system. This Rider substitutes for Rider DSI which terminates by its own terms. The Ohio Companies also agree not to collect certain amounts associated with RTEP and administrative costs associated with the move to PJM. Many of the existing riders approved in the previous ESP remain in effect, some with modifications. The new ESP also requests the resolution of current proceedings pending at the PUCO regarding corporate separation, elements of the smart grid proceeding and the move to PJM. The evidentiary hearing began on April 20, 2010, at the PUCO. The Stipulation requested a decision by the PUCO by May 5, 2010. On April 28, 2010, the PUCO Chairman issued a statement that the PUCO would not issue a decision on May 5, 2010, and would take additional time to review the case record. FirstEnergy recorded approximately $39.5 million of regulatory asset impairments and expenses related to the ESP. On May 12, 2010 a supplemental stipulation was filed that added two additional parties to the Stipulation, namely the City of Akron, Ohio and Council for Smaller Enterprises, to provide additional energy efficiency benefits. Pursuant to a PUCO Entry, a hearing was held on June 21, 2010 to consider the estimated bill impacts arising from the proposed ESP, and testimony was provided in support of the supplemental stipulation. On July 22, 2010, a second supplemental stipulation was filed that, among other provisions and if approved, would provide a commitment that retail customers of the Ohio Companies will not pay certain costs related to the companies’ integration into PJM, a regional transmission organization, for the longer of the five year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals $360 million, and establishes a $12 million fund to assist low income customers over the term of the ESP. Additional parties signing or not opposing the second supplemental stipulation include Northeast Ohio Public Energy Council (NOPEC), Northwest Ohio Aggregation Coalition (NOAC), Environmental Law and Policy Center and a number of low income community agencies. A hearing was held on the second supplemental stipulation on July 29, 2010. The matter is awaiting decision from the PUCO.
Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will 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 0.75% reduction each year thereafter through 2018. The PUCO may amend these benchmarks in certain, limited circumstances, and the Ohio Companies filed an application with the PUCO seeking such amendments. On January 7, 2010, the PUCO amended the Ohio Companies’ 2009 energy efficiency benchmarks to zero, contingent upon the Ohio Companies meeting the revised benchmarks in a period of not more than three years. On March 10, 2010, the PUCO found that the Ohio Companies peak demand reduction programs complied with PUCO rules.
On December 15, 2009, the Ohio Companies filed the required three year portfolio plan seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. On March 8, 2010, the Ohio Companies filed their 2009 Status Update Report with the PUCO in which they indicated compliance with the 2009 statutory energy efficiency and peak demand benchmarks as those benchmarks were amended as described above. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers. The Ohio Companies’ three year portfolio plan is still awaiting decision from the PUCO. The plan has yet to be approved by the PUCO, which is delaying the launch of the programs described in the plan. Without such approval, the Ohio Companies’ compliance with 2010 benchmarks is jeopardized and if not approved soon may require the Ohio Companies to seek an amendment to their annual benchmark requirements for 2010. Failure to comply with the benchmarks or to obtain such an amendment may subject the Companies to an assessment by the PUCO of a forfeiture.

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Additionally under SB221, 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. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RFPs sought RECs, including solar RECs and RECs generated in Ohio in order to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2009, 2010 and 2011. The RECs acquired through these two RFPs will be used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. On March 10, 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market. The PUCO reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies’ acquired through their 2009 RFP processes, provided the Companies’ 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. On April 15, 2010, the Ohio Companies and FES (due to its status as an electric service company in Ohio) filed compliance reports with the PUCO setting forth how they individually satisfied the alternative energy requirements in SB221 for 2009. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark, which application is still pending. On July 1, 2010, the Ohio Companies announced their intent to conduct an RFP in 2010 to secure RECs and solar RECs needed to meet the CBP

Ohio Companies’ alternative energy requirements as set forth in SB221. RFP bids are due August 3, 2010 and contracts are expected to be signed the week of August 9, 2010.
PennsylvaniaOn February 12, 2010, OE and CEI filed an application with the PUCO to establish a new credit for all-electric customers. On March 3, 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect on March 17, 2010. On April 15, 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that the new credit would remain in place through at least the 2011 winter season, and charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect on May 21, 2010. The Ohio Companies also filed on May 14, 2010 an application for rehearing of the Second Entry on Rehearing, which was granted for purposes of further consideration on June 9, 2010. No hearing has been scheduled in this matter.
As noted above in Note 8, FirstEnergy, CEI and OE filed a motion to dismiss a class action lawsuit related to the PUCO approved reduction of a discount that had previously been in place for residential customers with electric heating, electric water heating, or load management systems. The court has not yet ruled on that motion to dismiss.
Pennsylvania
Met-Ed and Penelec purchase a portion of their PLRPOLR 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 PLRPOLR 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 proposes129, with 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,August 12, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance filing tofiled a settlement agreement with 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 ingeneration procurement plan, reflecting the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero forsettlement on 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.but two reserved issues. On July 30,November 6, 2009, the PPUC entered an orderOrder approving the 5-year NUG Statement, approvingsettlement and finding in favor of Met-Ed and Penelec on the reductiontwo reserved issues. Generation procurement began in January 2010.
On February 8, 2010, Penn filed a Petition for Approval of its Default Service Plan for the CTC,period June 1, 2011 through May 31, 2013. The parties to the proceeding have reached a settlement on all issues and directingfiled a joint petition to approve the settlement agreement in July 2010. The PPUC is required to issue an order on the plan no later than November 8, 2010. If approved, procurement under the plan is expected to begin January 2011.
The PPUC adopted a Motion on January 28, 2010 and subsequently entered an Order on March 3, 2010 which denies the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, and directs Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructs Met-Ed and Penelec to work with the various intervening parties to file a tariff supplement implementing this change.recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. On July 31, 2009,March 18, 2010, Met-Ed and Penelec filed a Petition with the PPUC requesting that it stay the portion of the March 3, 2010 Order requiring the filing of tariff supplements decreasingto end collection of marginal transmission loss costs. By Order entered March 25, 2010, the CTCPPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC’s order, Met-Ed and Penelec filed the plan to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges and the plan for the use of these funds to mitigate future generation rate in complianceincreases commencing January 1, 2011. The PPUC approved this plan June 7, 2010.

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On April 1, 2010, Met-Ed and Penelec filed a Petition for Review with the July 30, 2009 order,Commonwealth Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. Although the ultimate outcome of this matter cannot be determined at this time, it is the belief of Met-Ed and increasingPenelec that they should prevail in the appeal and therefore expect to fully recover the approximately $199.7 million ($158.5 million for Met-Ed and $41.2 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011. On April 2, 2010, Met-Ed and Penelec filed a Response to the PPUC’s March 3, 2010 Order requesting approval of procedures to establish separate accounts to track all marginal transmission loss revenues and related interest and the use of those funds to mitigate future generation rate in complianceincreases commencing January 1, 2011, and the PPUC entered an Order on June 7, 2010, granting Met-Ed’s and Penelec’s request. On July 9 2010, Met-Ed and Penelec filed their briefs with the companies’ Restructuring OrdersCommonwealth Court of 1998. Pennsylvania. The Office of Small Business Advocate filed its brief on July 9, 2010. The PPUC’s brief is due to be filed in August 2010.
On August 14, 2009,May 20, 2010, the PPUC issued Secretarial Letters approving Met-Edapproved Met-Ed’s and Penelec’s compliance filings. annual updates to their TSC rider for the period June 1, 2010 through December 31, 2010 including marginal transmission losses as approved by the PPUC, although the recovery of marginal losses will be subject to the outcome of the proceeding related to the 2008 TSC filing as described above. The TSC for Met-Ed’s customers increased to be fully recovered by December 31, 2010.
Act 129 was enacted in 2008 to address issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Among other things Act 129 required utilities to file with the PPUC an energy efficiency and peak load reduction plan, or EE&C Plan, by July 1, 2009, setting forth the utilities’ plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of 4.5% by May 31, 2013. The PPUC entered an Order on February 26, 2010 approving the Pennsylvania Companies’ EE&C Plans and the tariff rider with rates effective March 1, 2010.
Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation Plan with the PPUC. This plan proposes a 24-month assessment period in which the Pennsylvania Companies will assess their needs, select the necessary technology, secure vendors, train personnel, install and test support equipment, and establish a cost effective and strategic deployment schedule, which currently is expected to be completed in fifteen years. Met-Ed, Penelec and Penn estimate assessment period costs at approximately $29.5 million, which the Pennsylvania Companies, in their plan, proposed to recover through an automatic adjustment clause. The ALJ’s Initial Decision approved the Smart Meter Plan as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; eliminating the provision of interest in the 1307(e) reconciliation; providing for the recovery of reasonable and prudent costs minus resulting savings from installation and use of smart meters; and reflecting that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. On April 15, 2010, the PPUC adopted a Motion by Chairman Cawley that modified the ALJ’s initial decision, and decided various issues regarding the Smart Meter Implementation Plan for the Pennsylvania Companies. The PPUC entered its Order on June 9, 2010, consistent with the Chairman’s Motion. On June 24, 2010, Met-Ed, Penelec and Penn filed a Petition for Reconsideration of a single portion of the PPUC’s Order regarding the future ability to roll smart meter costs into base rates.
Legislation addressing rate mitigation and the expiration of rate caps was introduced in the legislative session that ended in 2008; several bills addressing these issues were introduced in the 2009 legislative session. The final form and impact of such legislation is uncertain.
By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30 day30-day comment period on whether “thethe 1998 Restructuring Settlement allows Met-Ed and Penelec to apply over-collection of NUG over collectioncosts 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 werevarious parties 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 Alliancecomments objecting to the above accounting method utilized by Met-Ed and Penelec. The Companies filed reply comments on October 26, 2009,Met-Ed and awaitPenelec are awaiting further action by 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 SeptemberJune 30, 2009,2010, the accumulated deferred cost balance totaled approximately $102$81 million. To better align the recovery of expected costs, on July 26, 2010, JCP&L filed a request to decrease the amount recovered for the costs incurred under the NUG agreements by $180 million annually. If approved as filed, the change would not go into effect until January 1, 2011.

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In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004, supporting continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The 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 2009.2009 estimated at $736 million (in 2003 dollars). 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 dueOn April 16, 2010, the NJBPU issued an order indefinitely suspending the requirement of New Jersey utilities to be filed withsubmit Utility Master Plans until such time as the BPU by July 1, 2010.status of the EMP has been made clear. At this time, FirstEnergy and JCP&L cannot determine the impact, if any, the EMP may have on their operations.

In support of theformer New Jersey Governor'sGovernor Corzine’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 BPUNJBPU on August 19, 2009, and implementation will beginbegan in 2009. Approval for the project related to energy efficiency programs intended to complement those currently being offered was denied by the NJBPU on December 1, 2009. On July 6, 2010, the January 30, 2009 petition directed to infrastructure investment which had been pending before the NJBPU was withdrawn by JCP&L. 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")(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.rate based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a load flow methodology, referred to as “DFAX”, generally referred to as a “beneficiary pays” basis.approach to allocating the cost of high voltage transmission facilities. The FERC found that PJM’s current beneficiary-pays cost allocation methodology iswas 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 FERC ultimately issued an order approving use of the beneficiary pays method of cost allocation for transmission facilities included in the PJM regional plan that operate below 500 kV.
The FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. On February 11, 2008, AEPorder was 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,Circuit, which issued a decision on behalf of its affiliated operating utility companies, filed a motion to intervene on March 10,August 6, 2009. The Seventh Circuit Courtcourt affirmed FERC’s ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new 500+ kV facilities on a load ratio share basis and, based on this finding, remanded the rate design issue back to FERC.
In an order dated January 21, 2010, FERC set the matter for “paper hearings” — meaning that FERC called for parties to submit comments or written testimony pursuant to the schedule described in the order. FERC identified nine separate issues for comments, and directed PJM to file the first round of Appeals has held this appealcomments on February 22, 2010, with other parties submitting responsive comments within 45 days, and reply comments 30 days later. PJM filed certain studies with FERC on April 13, 2010, in abeyance pending resolutionresponse to the FERC order. PJM’s filing demonstrated that allocation of the Order 494 appeal discussed above.cost of high voltage transmission facilities on a beneficiary pays basis results in certain eastern utilities in PJM bearing the majority of their costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Certain eastern utilities and their state commissions supported continued socialization of these costs on a load ratio share basis. FERC is not expected to act before the fourth quarter of 2010.

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RTO Consolidation

On August 17, 2009,FERC issued an order approving, subject to certain future compliance filings, ATSI’s move to PJM. This allows 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 wouldwill 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. FERC approved FirstEnergy’s proposal to use a Fixed Resource Requirement Plan (FRR Plan) to obtain capacity to satisfy the PJM capacity requirements for the 2011-12 and 2012-13 delivery years.

To ensure a definitive ruling atIn December 2009, ATSI executed the same time FERC rules on its requestPJM Consolidated Transmission Owners Agreement and the Ohio Companies and Penn executed the PJM Operating Agreement and the PJM Reliability Assurance Agreement. Execution of these agreements committed ATSI and the Ohio Companies and Penn’s load to integrate ATSImoving into PJM on Octoberthe schedule described in the application and approved in the FERC Order.
FirstEnergy successfully conducted the FRR auctions on March 19, 2009, FirstEnergy filed a related complaint with FERC onand participated in the issue of allocating transmission costs toPJM base residual auction for the 2013 delivery year, thereby obtaining the capacity necessary for its ATSI footprint for high voltage transmission projects approved prior to FirstEnergy’s integration into PJM.

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meet PJM’s capacity requirements. FirstEnergy has requested that FERC rule on its application by December 17, 2009, to provide time to permit management to make a decision on whetherexpects 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 oneffective June 1, 2011, to coincide with delivery of power under the next competitive generation procurement process for FirstEnergy's Ohio companies.

2011.
On September 4, 2009, the PUCO opened a case to take comments from OhioOhio’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 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 forMISO Complaints Versus PJM Reliability Pricing Model (RPM) Auction

On May 30, 2008,March 9, 2010, MISO filed two complaints against PJM with FERC under Sections 206, 306 and 309 of the FPA alleging violations of the MISO/PJM Joint Operating Agreement (JOA). In Docket EL 10-46-000, the complaint alleges that PJM erroneously calculated charges to MISO for market-to-market settlements made from 2005 to 2009 pursuant to the congestion management provisions of the JOA. The MISO seeks approximately $130 million plus interest to correct for resultant net underpayments from PJM to MISO. In Docket No.EL10-45-000, MISO alleges that by failing to account for the market flows from 34 PJM generators over the period from 2007-2009, PJM underpaid MISO by a grouptotal of roughly $75 million including interest. For the period from 2005-2007, MISO claimed an underpayment by PJM load-serving entities, state commissions, consumer advocates,of at least $12 million plus interest. MISO also claimed that PJM failed to maintain required records necessary to calculate underbilling for the 2005-2007 billing.
In the second complaint, MISO alleged that PJM has refused to comply with provisions of the JOA requiring market-to-market dispatch since 2009, and trade associations (referredis improperly demanding repayment of redispatch payments previously made to collectively asMISO. PJM filed its answers to the RPM Buyers)complaints on April 12, 2010, opposing the relief sought by MISO.
In addition, on April 12, 2010, PJM filed a complaint at thewith FERC against PJMpursuant to Section 206, 306, and 309 alleging that threeMISO is violating the JOA with PJM by initiating market-to-market coordination and financial settlements for substitute (proxy) reciprocal coordinated flowgates between MISO and PJM. PJM claims that the JOA does not permit MISO to initiate market-to-market settlements using proxy flowgates in lieu of designated reciprocal coordinated flowgates. This complaint addresses substantially the same issues as the second MISO complaint, in which MISO argues that the use of proxy flowgates is permitted by agreement of the four transitional RPM auctions yielded prices that are unjustRTOs and unreasonable under the Federal Power Act. operating practice. Each party filed a complaint in order to ensure their right to claim refunds, if any, if successful in their arguments at FERC.
On September 19, 2008, theJune 29, 2010, 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 terminatingconsolidating the cases and establishing settlement discussions. On February 9, 2009, PJM and a groupjudge procedures. If the settlement process is unsuccessful, the cases will proceed to evidentiary hearings. FirstEnergy is unable to predict the outcome 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.this matter.

MISO Multi-Value Project Rule Proposal
On March 26, 2009,July 15, 2010, MISO and certain MISO transmission owners jointly filed with the FERC accepted intheir proposed cost allocation methodology for new transmission projects. If approved, so-called Multi Value Projects (MVPs) — transmission projects that have a regional impact and are part and rejected in part, tariff provisions submittedof a regional plan — will have a 100% regional allocation of costs under the proposed methodology. If approved by PJM, revising certain parts of its RPM. Ordered changes included making incremental improvementsFERC, MISO’s proposal is expected to RPM;   clarification on certain aspectspermit the allocation of the March 26, 2009 Order. On April 27, 2009, PJM submittedcosts of large transmission projects designed to integrate wind from the upper Midwest across the entire MISO. MISO has requested 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 acceptedfiling by the PUCO on May 14, 2009. Twelve bidders qualifiedFERC’s December open meeting, but an effective date for its proposal of July 16, 2011. Under MISO’s proposal, the costs of MVP projects approved by MISO’s Board prior 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 amount2011 effective date of capacity resources requiredFirstEnergy’s integration into PJM would continue to be supplied by FESallocated 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.FirstEnergy.

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 FirstEnergyCompliance with regard to environmental mattersregulations could have a material adverse effect on FirstEnergy'sFirstEnergy’s earnings and competitive position to the extent that itFirstEnergy 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.

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CAA Compliance

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 and NOX emissions regulations.regulations under the CAA. FirstEnergy complies with SO2 and NOx reduction requirements under the CAA and State Implementation Plan(s) under the CAA (SIPs) by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower-emitting plants, and/or using emission allowances. 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.penalties.

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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 are operated under a consent decree with the EPA and DOJ that requires reductions of NOX and SO2 emissions through the installation of pollution control devices or repoweringrepowering. OE and provides forPenn are subject to 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,combustion, are currently estimated to be $706approximately $399 million for 2009-2012 (with $414 million expected to be spent in 2009).2010-2012.

On May 22,In 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing ofPennFuture filed 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,limitations, in the United StatesU.S. District Court for the Western District of Pennsylvania. In July 2008, three additional complaints were filed against FGCO in the United StatesU.S. District Court for the Western District of Pennsylvania also seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, twoTwo of the threethese complaints also 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, aA 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 dismissedPennFuture. FGCO believes 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 claimsremaining plaintiffs 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 statestates of New Jersey and Connecticut filed a CAA citizen suitsuits in 2007 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 Jerseythese suits allege that "modifications"“modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR or permitting under the CAA's prevention of significant deteriorationCAA’s PSD 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 ofIn September 2009, 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'sMet-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 statutepenalties. The parties dispute the scope of limitations grounds in orderMet-Ed’s indemnity obligation 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.and from Sithe Energy.


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OnIn January 14, 2009, the EPA issued a NOV to Reliant alleging new source reviewNSR 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, NOV1986 and also alleged new source reviewNSR violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. Met-Ed, 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.
OnIn June 11, 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. alleging that "modifications"“modifications” at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or permitting under the CAA's preventionCAA’s PSD program. In May 2010, the EPA issued a second NOV to Mission Energy Westside, Inc., Penelec, NYSEG and others that have had an ownership interest in the Homer City Power Station containing in all material respects identical allegations as the June 2008 NOV. On July 20, 2010, the states of significant deterioration program.New York and Pennsylvania provided Mission Energy Westside, Inc., Penelec, NYSEG and others that have had an ownership interest in the Homer City Power Station a notification required 60 days prior to filing a citizen suit under the CAA. 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.under dispute and 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. OnIn August 12, 2009, the EPA issued a Finding of Violation and NOV alleging violations of the Clean Air ActCAA and Ohio regulations, including the prevention of significant deterioration (“PSD”), non-attainment new source review (NNSR”),PSD, 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 informationa request pursuant to Section 114(a) of the Clean Air Act requiring FirstEnergy to submitfor certain operating and maintenance information and planning information regarding the Eastlake, Lake Shore, Bay Shorefor these same generating plants 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 provisionsprovision of the CAA. Later in 2009, FGCO received another information request regarding emission projections for the Eastlake generating plant. FGCO intends to comply with the CAA, including the 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.

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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.The EPA’s CAIR requires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, (2009/2010 for SO2and Phase II in 2015 for both NOX and SO2)2015), 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 inIn 2008, the United StatesU.S. 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. OnIn 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 StatesThe 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"“8-hour” ozone NAAQS. FGCO'sIn July 2010, the EPA proposed the Clean Air Transport Rule (CATR) to replace CAIR, which remains in effect until the EPA finalizes CATR. CATR requires reductions of NOX and SO2 emissions in two phases (2012 and 2014), ultimately capping SO2 emissions in affected states to 2.6 million tons annually and NOX emissions to 1.3 million tons annually. The EPA proposed a preferred regulatory approach that allows trading of NOX and SO2 emission allowances between power plants located in the same state with severe limits on interstate trading and two alternative approaches—the first eliminates interstate trading of NOX and SO2 emission allowances and the second eliminates trading of NOX and SO2 emission allowances in its entirety. Depending on the actions taken by the EPA with respect to CATR, the proposed MACT regulations discussed below, and any future regulations that are ultimately implemented, FGCO’s future cost of compliance with these regulations may be substantialsubstantial. Management is currently assessing the impact of these environmental proposals and will depend, in part,other factors on FCGO’s facilities, particularly on the action taken by the EPA in responseoperation of its smaller, non-supercritical units. For example, management may decide to the Court’s ruling.idle certain of these units or operate them on a seasonal basis until developments clarify.

Hazardous Air Pollutant Emissions
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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 theThe EPA’s CAMR which provides for a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping nationalnationwide emissions of mercury emissions at 38 tons by 2010 (as a "co-benefit"“co-benefit” from implementation of SO2 and NOX emission caps under the EPA'sEPA’s CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United StatesThe U.S. Court of Appeals for the District of Columbia. On February 8, 2008,Columbia, at the Courturging of several states and environmental groups 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 openedentered into a 30-day comment period on a proposed consent decree that would obligate the EPArequiring it 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 withOn April 29, 2010, the EPA issued proposed MACT regulations may be substantialrequiring emissions reductions of mercury and will dependother hazardous air pollutants from non-electric generating unit boilers, including boilers which do not use fossil fuels such as the proposed Burger biomass repowering project. If finalized, the non-electric generating unit MACT regulations could also provide precedent for MACT standards applicable to electric generating units. Depending on the action taken by the EPA and on how any future regulations are ultimately implemented.
implemented, FGCO’s future cost of compliance with MACT regulations may be substantial and changes to FGCO’s operations may result.
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,December 23, 2009, the Supreme Court of Pennsylvania affirmed the Commonwealth Court of Pennsylvania declaredruling that Pennsylvania’s mercury rule is “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. 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. 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 theThe 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 thoseelectric generating plants and other facilities. On April 17,In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that will require FirstEnergy to measure GHG emissions commencing in 2010 and submit reports commencing in 2011. In December 2009, the EPA released a “Proposed Endangermentits final “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 toGHG increase the threat of climate change. AlthoughIn April 2010, the EPA’s proposed finding, ifEPA finalized doesnew GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles and clarified that GHG regulation under the CAA will not establish emission requirementsbe triggered 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 supportand other stationary sources until January 2, 2011, at the establishment of future emission requirements byearliest. In May 2010, 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 programsCAA program would be required. The EPA is proposing a major sourceestablished an emissions applicability threshold of 25,00075,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) effective January 2, 2011 for existing facilities under the Title V operating permits program and theCAA’s Prevention of Significant Determination (PSD) portionprogram, but until July 1, 2011 that emissions applicability threshold will only apply if PSD is triggered by non-carbon dioxide pollutants.

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At the international level, the Kyoto Protocol, signed by the U.S. in 1998 but never submitted for ratification by the U.S. Senate, was intended to address global warming by reducing the amount of NSR. EPA is also proposingman-made GHG, including CO2, emitted by developed countries by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a significance level between 10,000consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement which recognized the scientific view that the increase in global temperature should be below two degrees Celsius, included a commitment by developed countries to provide funds, approaching $30 billion over the next three years with a goal of increasing to $100 billion by 2020, and 25,000 tpy CO2eestablished the “Copenhagen Green Climate Fund” to determine if existing major sources making modifications that resultsupport mitigation, adaptation, and other climate-related activities in an increase ofdeveloping countries. Once they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia, and the United States, would commit to quantified economy-wide emissions above the significance leveltargets from 2020, while developing countries, including Brazil, China, and India, would be requiredagree to obtain a PSD permit.take mitigation actions, subject to their domestic measurement, reporting, and verification.


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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.grounds; however, a subsequent ruling from the U.S. Court of Appeals for the Fifth Circuit reinstated the lower court dismissal of a complaint alleging damage from GHG emissions. 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 eitherthis litigation, should the courtscourt of appeals decisionsdecision be affirmed or not subjected to further review, 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'sFirstEnergy’s plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FirstEnergy'sFirstEnergy’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, theThe 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'sfacility’s cooling water system). On January 26, 2007,The EPA has taken 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, notingposition 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 U.S. Supreme Court of the United States reversed one significant aspect of the Second Circuit Court’sCircuit’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 considerationis developing a new regulation under Section 316(b) of the rule on remand and take further actionClean Water Act 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’ opinionswhich have created significant uncertainty about the specific nature, scope and timing of the final compliance requirements .FirstEnergyperformance standard. FirstEnergy is studying various control options and their costs and effectiveness.effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant’s water intake channel to divert fish away from the plant’s water intake system. On March 15, 2010, the EPA issued a draft permit for the Bay Shore power plant requiring installation of reverse louvers in its entire water intake channel by December 31, 2014. Depending on the results of such studies and the EPA’s further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

TheIn June 2008, the U.S. Attorney'sAttorney’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

AsFederal and state hazardous waste regulations have been promulgated 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.1976. Certain fossil-fuel combustion waste products,residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA'sEPA’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,residuals, including whether they should be regulated as hazardous or non-hazardous waste.

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On December 30, 2009, in an advanced notice of public rulemaking, the EPA said that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. On May 4, 2010, the EPA proposed two options for additional regulation as non-hazardous waste orof coal combustion residuals, including the option of regulation as a hazardous waste. In March and June 2009,special waste under 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 aEPA’s 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 productsmanagement program which could have a significant impact on ourthe management, beneficial use and disposal of coal ash. FGCO'scombustion residuals. FGCO’s future cost of compliance with any coal combustion wasteresiduals 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 EPA or 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 SeptemberJune 30, 2009,2010, based on estimates of the total costs of cleanup, the Utilities'Utilities’ proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $104$105 million (JCP&L - - $77— $76 million, TE - $1 million, CEI - $1 million, FGCO - $1 million and FirstEnergy - $24— $26 million) have been accrued through SeptemberJune 30, 2009.2010. Included in the total are accrued liabilities of approximately $68$67 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&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'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)Early in 2010, the Appellate Division limited the class only to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, basedheard oral argument 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 theirplaintiff’s appeal of the trial court'scourt’s decision decertifying the class. JCP&L is now waiting forclass, and on July 29, 2010, the Appellate Division upheld the trial court’s decision.
Litigation Relating to schedule the appealProposed Allegheny Energy Merger
In connection with the proposed merger (Note 15), purported shareholders of Allegheny Energy have filed putative shareholder class action and/or derivative lawsuits in Pennsylvania and Maryland state courts, as well as in the U.S. District Court for the Western District of Pennsylvania, against Allegheny Energy and its directors and certain officers, referred to as the Allegheny Energy defendants, FirstEnergy and Merger Sub. In summary, the lawsuits allege, among other things, that the Allegheny Energy directors breached their fiduciary duties by approving the merger agreement, and that Allegheny Energy, FirstEnergy and Merger Sub aided and abetted in these alleged breaches of fiduciary duty. The complaints seek, among other things, jury trials, money damages and injunctive relief. Additional details about the actions are provided below. While FirstEnergy believes the lawsuits are without merit and has defended vigorously against the claims, in order to avoid the costs associated with the litigation, the defendants have agreed to the terms of a disclosure-based settlement of the lawsuits. The defendants reached an agreement with counsel for all of the plaintiffs concerning fee applications, but a formal stipulation of settlement has not yet been filed with any court. If the parties are unable to obtain final approval of the settlement, then litigation will proceed, and the outcome of any such litigation is inherently uncertain. If a dismissal is not granted or a settlement is not reached, these lawsuits could prevent or delay the completion of the merger and result in substantial costs to FirstEnergy. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger closes may adversely affect FirstEnergy’s business, financial condition or results of operations.
Four putative class action and derivative lawsuits were filed in the Circuit Court for Baltimore City, Maryland. One was withdrawn. The court consolidated the three cases under the captionOakmont Capital Management, LLC v. Evanson, et al., C.A. No. 24-C-10-1301, and appointed Lewis M. Lynn as Lead Plaintiff. Plaintiff Lynn filed a Consolidated Amended Complaint on April 12, 2010. On April 21, 2010, defendants filed Motions to Dismiss the Consolidated Amended Complaint for failure to state a claim. The court has stayed all discovery pending resolution of those motions. The court also has entered a stipulated order certifying a class with no opt-out rights. On May 27, 2010, the parties reported to the court that they have agreed to the terms of a disclosure-based settlement and requested that the court cancel the oral arguments.argument on the motions to dismiss that had been scheduled for June 3, 2010. On May 28, 2010, the court removed the hearing from its calendar.

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Three shareholder lawsuits were filed in the Court of Common Pleas of Westmoreland County, Pennsylvania, raising putative class action and derivative claims against the Allegheny Energy directors and officers, FirstEnergy and Allegheny Energy. The court has consolidated these actions under the caption,In re Allegheny Energy, Inc. Shareholder Class and Derivative, Litigation, Lead Case No. 1101 of 2010, and appointed lead counsel. On April 5, 2010, the Allegheny Energy defendants filed a Motion to Stay the Proceedings. Shortly thereafter, FirstEnergy similarly filed a Motion to Stay. Plaintiffs filed a Motion for Expedited Discovery. The court scheduled a hearing on the motions for May 27, 2010. On May 21, 2010, plaintiffs filed a Verified Consolidated Shareholder Derivative and Class Complaint. On May 26, 2010, the parties filed a Motion for a Continuance of the May 27 hearing, which the court granted. On June 1, 2010, the parties reported to the court that they have agreed to the terms of a disclosure-based settlement.

A putative shareholder lawsuit styled as a class action was filed in the U.S. District Court for the Western District of Pennsylvania and is captionedLouisiana Municipal Police Employees’ Retirement System v. Evanson, et al., C.A. No. 10-319 NBF. On June 1, 2010, the parties reported to the court that they have agreed to the terms of a disclosure-based settlement.
Nuclear Plant Matters

During a planned refueling outage that began on February 28, 2010, FENOC conducted a non destructive examination and testing of the Control Rod Drive Mechanism (CRDM) Nozzles of the Davis-Besse reactor pressure vessel head. FENOC identified flaws in CRDM nozzles that required modification. The NRC was notified of these findings, along with federal, state and local officials. On March 17, 2010, the NRC sent a special inspection team to Davis-Besse to assess the adequacy of FENOC’s identification, analyses and resolution of the CRDM nozzle flaws and to ensure acceptable modifications were made prior to placing the RPV head back in service. After successfully completing the modifications, FENOC committed to take a number of corrective actions including strengthening leakage monitoring procedures and shutting Davis-Besse down no later than October 1, 2011, to replace the reactor pressure vessel head with nozzles made of material less susceptible to primary water stress corrosion cracking further enhancing the safe and reliable operations of the plant. On June 29, 2010, FENOC returned Davis-Besse to service.
In August 2007, FENOC submitted an applicationOn April 5, 2010, the Union of Concerned Scientists (UCS) requested that the NRC issue a Show Cause Order, or otherwise delay the restart of the Davis-Besse Nuclear Power Station until the NRC determines that adequate protection standards have been met and reasonable assurance exists that these standards will continue to be met after the plant’s operation is resumed. By a letter dated July 13, 2010, the NRC denied UCS’s request for immediate action because “the NRC has conducted rigorous and independent assessments of returning the Davis-Besse reactor vessel head to service and its continued operation, and determined that it was safe for the plant to restart.” The UCS petition was referred to a petition manager for further review. What additional actions, if any that the NRC takes in response 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.

UCS request, have not been determined.
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of Septemberobligations. As of June 30, 2009,2010, 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 byBy a letter dated March 8, 2010, primarily as a result of the Beaver Valley Power Station operating license renewal, FENOC requested that the NRC FirstEnergy annually recalculates and adjusts the amount of itsreduce FirstEnergy’s parental guarantee as appropriate. The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based on market conditions. Ifto $15 million and notified the value ofstaff that it no longer planned to make the trusts decline byadditional contributions into the trusts. By a material amount, FirstEnergy’s obligationsletter dated July 14, 2010, the NRC stated that it had no objection to fund the trusts may increase. The recent disruptionreduction 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.guarantee.
117


Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy'sFirstEnergy’s normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
On April 14, 2010, JCP&L's&L reached an agreement on a settlement package with its bargaining unit employees filedregarding a grievance challenging JCP&L's&L’s 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004,The agreement included an arbitration panel concluded thatagreed-upon settlement amount and extension of the call-out procedure violated the parties' collective bargaining agreement. On September 9, 2005,July 22, 2010, the arbitration panel issuedcourt signed an opinionorder approving and implementing the parties’ agreement. As of June 30, 2010, JCP&L reduced its reserve to award approximately $16$9 million for the settlement which will be paid to the employees over the next thirty days beginning on July 25, 2010. The collective bargaining unit employees. A final order identifyingagreement extension is also effective as of July 25, 2010.

101


On February 16, 2010, a class action lawsuit was filed in Geauga County Court of Common Pleas against FirstEnergy, CEI and OE seeking declaratory judgment and injunctive relief, as well as compensatory, incidental and consequential damages, on behalf of a class of customers related to the individual damage amountsreduction of a discount that had previously been in place for residential customers with electric heating, electric water heating, or load management systems. The reduction in the discount was issued on October 31, 2007 andapproved by the award appeal process was initiated. The unionPUCO. On March 18, 2010, the named-defendant companies filed a motion withto dismiss the federal Courtcase due to confirm the award and JCP&L filed its answer and counterclaim to vacatelack of jurisdiction of the awardcourt of common pleas. The court has not yet ruled 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’sthat motion to vacate the arbitration decision and granted the union’s motiondismiss. The named-defendant companies will continue 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.

defend these claims including challenging any class certification.
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'sFirstEnergy’s or its subsidiaries'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 TopicSee Note 10 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 significantCombined Notes to the VIE. This standard also requires ongoing reassessmentsConsolidated Financial Statements (Unaudited) for discussion 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.new accounting pronouncements.

102

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'SMANAGEMENT’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'sFirstEnergy’s fossil and hydroelectric generation facilities, and owns FirstEnergy'sFirstEnergy’s nuclear generation facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities.

FES'FES’ revenues have been primarilyare derived from sales to individual retail customers, sales to communities in the form of government aggregation programs, the sale of electricity (provided from FES' generating facilitiesto Met-Ed and through purchased power arrangements) to affiliated utility companiesPenelec to meet all or a portion of their PLRPOLR 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 suppliesits participation in the event of failure of supply of the assigned energy purchase contracts. Prices for the power sold by FES were increased to $42.77affiliated 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'non-affiliated POLR auctions. FES’ revenues also include competitive retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania, New Jersey, Maryland, Michigan, Illinois 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.

Maryland.
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.

conditions.
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 ManagementFirstEnergy’s Management’s 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, Market Risk Information, Credit Risk, Outlook and Outlook.New Accounting Standards and Interpretations.

Results of Operations

InNet income decreased by $254 million in the first ninesix months of 2009, net income decreased2010, compared to $80 million from $166 million in the same period of 2008.2009. 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 increasedwas primarily due to higher average prices across all customer classespurchased power costs, the absence of a $252 million ($158 million after tax) gain in 2009 from the sale of a 9% participation interest in OVEC and increased KWH salesfuel and interest expense, partially offset by higher revenues and investment income.
Revenues
Total revenues, excluding the OVEC sale, increased $388 million in the first six months of 2010, compared to residential and commercial customers, reflecting a decrease in customer shopping in those sectors as mostthe same period 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 increased2009 primarily due to an increase in OE's fuel cost recovery riderdirect and government aggregation sales volumes and sales of RECs, partially offset by decreases in POLR sales to the Ohio Companies and wholesale sales.
The increase in revenues resulted from the following sources:
             
  Six Months    
  Ended June 30  Increase 
Revenues by Type of Service 2010  2009  (Decrease) 
  (In millions) 
Direct and Government Aggregation $1,097  $174  $923 
POLR  1,260   1,732   (472)
Wholesale  186   311   (125)
Transmission  36   41   (5)
RECs  67      67 
Sale of OVEC participation interest     252   (252)
Other  57   57    
          
Total Revenues
 $2,703  $2,567  $136 
          
The increase in direct and government aggregation revenues of $923 million resulted from increased revenue in both the MISO and PJM markets. The increase in revenue primarily resulted from the acquisition of new commercial and industrial customers, as well as new government aggregation contracts with communities in Ohio that provide generation to approximately 1.1 million residential and small commercial customers at the end of June 2010 compared to approximately 21,000 at the end of June 2009, partially offset by lower unit prices. During January 2010, FES began supplying power to approximately 425,000 NOPEC customers.

103


The decrease in POLR revenues of $472 million was effectivedue to lower sales volumes to the Ohio Companies and lower unit prices, partially offset by increased sales volumes and higher unit prices to the Pennsylvania Companies. The lower sales volumes and unit prices to the Ohio Companies in 2010 reflected the results of the May 2009 power procurement process. The increased revenues to the Pennsylvania Companies resulted from JanuaryFES supplying Met-Ed and Penelec with volumes previously supplied through Maya third-party contract at prices that were slightly higher than in 2009. Effective June 1, 2009,
Wholesale revenues decreased $125 million due to reduced volumes reflecting market declines and lower prices.
The following tables summarize the transmission tariff endedprice and the recovery of transmission costs is includedvolume factors contributing to changes in therevenues from generation rate established under OE’s CBP.sales:

     
  Increase 
Source of Change in Direct and Government Aggregation (Decrease) 
  (In millions) 
Direct Sales:    
Effect of increase in sales volumes $633 
Change in prices  (47)
    
   586 
    
Government Aggregation    
Effect of an increase in sales volumes  337 
Change in prices   
    
   337 
    
Net Increase in Direct and Gov’t Aggregation Revenues
 $923 
    
Changes in retail generation sales and
     
Source of Change in Wholesale Revenues (Decrease) 
  (In millions) 
POLR:    
Effect of 15.1% decrease in sales volumes $(262)
Change in prices  (210)
    
   (472)
    
Wholesale:    
Effect of 56.7% decrease in sales volumes  (123)
Change in prices  (2)
    
   (125)
    
Decrease in Wholesale Revenues
 $(597)
    
Transmission revenues decreased $5 million due primarily to lower PJM congestion revenue.
Expenses
Total expenses increased $539 million in the first ninesix months of 20092010, compared with the same period of 2009.
The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first six months of 2010, from the same period in 2008 are summarized in the following tables:last year:

     
  Increase 
Source of Change in Fuel and Purchased Power (Decrease) 
  (In millions) 
Fossil Fuel:    
Change due to increased unit costs $33 
Change due to volume consumed  40 
    
   73 
    
Nuclear Fuel:    
Change due to increased unit costs  18 
Change due to volume consumed  3 
    
   21 
    
Non-affiliated Purchased Power:    
Power contract mark-to-market adjustment  17 
Change due to decreased unit costs  (98)
Change due to volume purchased  484 
    
   403 
    
Affiliated Purchased Power:    
Change due to decreased unit costs  (4)
Change due to volume purchased  19 
    
   15 
    
Net Increase in Fuel and Purchased Power Costs
 $512 
    

104


Retail Generation KWH Sales
Increase
(Decrease)
Residential6.6 %
Commercial10.4 %
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 $203Fossil fuel costs increased $73 million in the first ninesix months of 20092010, 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,of 2009, as a result of higher volumes consumed combined 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 revenuesincreased prices. Increased volume reflects higher generation in the first ninesix months of 2009 from the same period in 2008 are summarized in the following tables.

Distribution KWH DeliveriesDecrease
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 20092010, compared to the same period last year due to improving economic conditions. The increased costs reflect higher coal and transportation charges in 2008the first six months of 2010, compared to the same period last year. Nuclear fuel costs increased $21 million, primarily due to the replacement of nuclear fuel at higher unit costs following the refueling outages that occurred in 2009.
Non-affiliated purchased power costs increased $403 million due primarily to higher volumes purchased and a power contract mark-to-market adjustment, partially offset by lower unit costs. The increase in volume primarily relates to the assumption of a 1,300 MW contract from Met-Ed and Penelec. Affiliated purchased power increased primarily due to higher interest expensevolumes purchased from affiliated companies due to the Perry nuclear refueling outage in 2009.
Other operating expenses increased $23 million in the first six months of 2010, compared to the same period of 2009, primarily due to increased transmission expenses ($33 million) and increased uncollectible customer accounts and agent fees associated with the issuancegrowth in direct and government aggregation sales ($19 million), partially offset by lower nuclear operating costs ($37 million).
General taxes increased $4 million due to sales taxes associated with increased revenues.
Other Expense
Total other expense decreased $2 million in the first six months of $3002010, compared to the same period of 2009, primarily due to a $36 million increase in investment income resulting from more favorable performance of FMBsnuclear decommissioning trust investments, partially offset by OEa $31 million increase in October 2008.interest expense (net of capitalized interest). Interest expense increased primarily due to new long-term debt issued in the second half of 2009 combined with the restructuring of existing long-term debt.

105



OHIO EDISON COMPANY
MANAGEMENT’S NARRATIVE
123




THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT'S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS


CEIOE is a wholly owned electric utility subsidiary of FirstEnergy. CEI conductsOE and its wholly owned subsidiary, Penn, conduct business in northeasternportions of Ohio and Pennsylvania, providing regulated electric distribution services. CEI also providesThey procure generation services tofor those franchise customers electing to retain CEIOE and Penn 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,OE, please see the information contained in FirstEnergy's ManagementFirstEnergy’s Management’s 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, Market Risk Information, Credit Risk, Outlook and Outlook.New Accounting Standards and Interpretations.

Results of Operations

CEI experienced a net loss of $32Earnings available to parent increased by $28 million in the first ninesix 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 20092010, compared to the same period of 20082009. The increase primarily resulted from lower purchased power costs and other operating costs, partially offset by lower revenues.
Revenues
Revenues decreased $473 million, or 33.3%, in the first six months of 2010, compared with the same period in 2009, due primarily to a decrease in generation revenues. Distribution revenues also were lower than they were in the first half of 2009.
Retail generation revenues decreased $438 million primarily due to decreasesa decrease in KWH sales in all customer classes, partially offset by higher average prices in the commercial and industrial classes. Lower KWH sales were primarily the result of a 46.1% increase in customer shopping in the first six months of 2010. Lower KWH sales to residential customers were partially offset by increased weather-related usage in the first six months of 2010, reflecting a 62% increase in cooling degree days in OE’s service territory. Higher average prices in the commercial and industrial classes resulted from the CBP auction for the service period beginning June 1, 2009.
Changes in retail generation KWH sales and revenues in the first six months of 2010, compared to the same period in 2009, are summarized in the following tables:
Retail Generation KWH SalesDecrease
Residential(30.3)%
Commercial(60.0)%
Industrial(64.3)%
Decrease in Retail Generation Sales
(48.1)%
     
Retail Generation Revenues Decrease 
  (In millions) 
Residential $(143)
Commercial  (167)
Industrial  (128)
    
Decrease in Retail Generation Revenues
 $(438)
    
Distribution revenues decreased $17 million in the first six months of 2010, compared to the same period in 2009, due to lower commercial and industrial revenues, partially offset by higher residential revenues. Commercial and industrial revenues were primarily impacted by lower average unit prices, resulting from lower transmission rates in 2010. Residential distribution revenues were higher due to higher average unit prices resulting from the 2009 ESP and slightly higher KWH deliveries resulting from the warmer conditions described above. Increased industrial deliveries were the result of improving economic conditions, reflecting an increase in KWH deliveries to major steel customers (36%) and automotive customers (27%).

106


Changes in distribution KWH deliveries and revenues ($117 million), transmissionin the first six months of 2010, compared to the same period in 2009, are summarized in the following tables:
Distribution KWH SalesIncrease
Residential0.2%
Commercial0.7%
Industrial12.7%
Increase in Distribution Deliveries
4.0%
     
  Increase 
Distribution Revenues (Decrease) 
  (In millions) 
Residential $9 
Commercial  (8)
Industrial  (18)
    
Net Decrease in Distribution Revenues
 $(17)
    
Wholesale revenues ($14 million) and other miscellaneous revenues ($7 million),decreased $11 million primarily due to lower unit prices, partially offset by an increase in sales to FES from OE’s leasehold interests in Perry Unit 1 and Beaver Valley Unit 2.
Expenses
Total expenses decreased $521 million in the first six months of 2010, from the same period of 2009. The following table presents changes from the prior period by expense category:
     
Expenses — Changes (Decrease) 
  (In millions) 
Purchased power costs $(422)
Other operating expenses  (93)
Amortization of regulatory assets, net  (4)
General taxes  (2)
    
Decrease in Expenses
 $(521)
    
Purchased power costs decreased in the first six months of 2010, compared to the same period of 2009, primarily due to lower KWH purchases resulting from increased customer shopping in the first six months of 2010 and slightly lower unit costs. The decrease in other operating costs for the first six months of 2010, was primarily due to lower MISO transmission expenses (assumed by third party suppliers beginning June 1, 2009) and the absence in 2010 of $18 million of costs incurred in the first six months of 2009 associated with regulatory obligations for economic development and energy efficiency programs under OE’s 2009 ESP. Lower amortization of net regulatory assets was primarily due to lower amortization of deferred MISO transmission costs, partially offset by the recovery of certain regulatory assets that began in 2010. The decrease in general taxes was primarily due to lower Ohio KWH taxes and lower property taxes.

107


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 procures generation services for those customers electing to retain CEI as their power supplier.
For additional information with respect to CEI, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Earnings increased by $94 million in the first six months of 2010, compared to the same period of 2009. The increase in earnings was primarily due to the absence in 2010 of one-time regulatory charges recognized in 2009, and decreased purchased power and other operating costs, partially offset by decreased revenues and deferred regulatory assets.
Revenues
Revenues decreased $299 million, or 32%, in the first six months of 2010, compared to the same period of 2009, due to decreased retail generation revenues ($103 million).

and distribution revenues.
Retail generation revenues increaseddecreased $200 million in the first ninesix months of 2010, compared to the same period of 2009, primarily due to lower KWH sales across all customer classes, partially offset by higher average unit prices in all customer classesclasses. Reduced KWH sales were primarily the result of increased customer shopping in the first six months of 2010. Lower KWH sales to residential customers were partially offset by decreased sales volume to residential and industrial customers compared toincreased weather-related usage in the same periodfirst six months of 2008. Average2010, reflecting a 113% increase in cooling degree days. Retail generation prices increased due to an increase in CEI’s fuel cost recovery rider that was effective from January through May 2009. In addition, effective2010 as a result of the CBP auction for the service period beginning 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.

2009.
Changes in retail generation sales and revenues in the first ninesix months of 20092010, compared to the same period in 2008of 2009, are summarized in the following tables:

Retail Generation KWH SalesDecrease
Residential(54.3)%
Commercial(68.5)%
Industrial(49.2)%
Decrease in Retail Generation Sales
(55.6)%
     
Retail Generation Revenues Decrease 
  (In millions) 
Residential $(50)
Commercial  (80)
Industrial  (70)
    
Decrease in Retail Generation Revenues
 $(200)
    
Distribution revenues decreased $91 million in the first six months of 2010, compared to the same period of 2009, due to lower average unit prices for all customer classes and decreased KWH deliveries in the residential sector, partially offset by increased KWH deliveries in the industrial and commercial sectors. The lower average unit prices were the result of lower transition rates in 2010. Increased industrial deliveries were the result of improving economic conditions, reflecting an increase in KWH deliveries to major steel customers (158%) and automotive customers (14%).

108


Changes in distribution KWH deliveries and revenues in the first six months of 2010, compared to the same period of 2009, are summarized in the following tables:
Increase
Distribution KWH Sales(Decrease)
Residential(0.6)%
Commercial1.7%
Industrial12.0%
Net Increase in Distribution Deliveries
5.1%
     
Distribution Revenues Decrease 
  (In millions) 
Residential $(13)
Commercial  (28)
Industrial  (50)
    
Decrease in Distribution Revenues
 $(91)
    
Expenses
Total expenses decreased $452 million in the first six months of 2010, compared to the same period of 2009. The following table presents the change from the prior period by expense category:
     
  Increase 
Expenses — Changes (Decrease) 
  (In millions) 
Purchased power costs $(325)
Other operating costs  (44)
Amortization of regulatory assets, net  (210)
Deferral of new regulatory assets  135 
General taxes  (8)
    
Net Decrease in Expenses
 $(452)
    
Purchased power costs decreased in the first six months of 2010, primarily due to lower KWH sales requirements as discussed above. Other operating costs decreased due to lower transmission expenses (assumed by third party suppliers beginning June 1, 2009), labor and employee benefit expenses and the absence in 2010 of $12 million of costs incurred in the first six months of 2009 associated with regulatory obligations for economic development and energy efficiency programs. Decreased amortization of regulatory assets was due primarily to the 2009 impairment of CEI’s Extended RTC regulatory asset of $216 million in accordance with the PUCO-approved ESP. A decrease in the deferral of new regulatory assets was primarily due to CEI’s contemporaneous recovery of purchased power costs in 2010. General taxes decreased in the first six months of 2010, primarily due to a 2010 favorable tax settlement in Ohio.
Other Expense
Other expense increased $4 million in the first six months of 2010, compared to the same period of 2009 due to lower investment income and higher interest expense associated with the August 2009 issuance of $300 million first mortgage bonds, partially offset by the November 2009 redemption of $150 million senior secured notes.

109


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 procures generation services for those customers electing to retain TE as their power supplier.
For additional information with respect to TE, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Earnings available to parent increased by $7 million in the first six months of 2010, compared to the same period of 2009. The increase was primarily due to decreased net amortization of regulatory assets, purchased power and other operating costs, partially offset by an increase in interest expense and decreases in revenues and investment income.
Revenues
Revenues decreased $218 million, or 46%, in the first six months of 2010, compared to the same period of 2009, primarily due to lower retail generation and distribution revenues, partially offset by an increase in wholesale generation revenues.
Retail generation revenues decreased $203 million in the first six months of 2010, compared to the same period of 2009, primarily due to lower KWH sales across all customer classes and lower unit prices to industrial customers. Lower KWH sales to all customer classes were primarily the result of a 63% increase in customer shopping in the first six months of 2010. Lower unit prices for industrial customers are primarily due to the absence of TE’s fuel cost recovery and rate stabilization riders that were effective from January through May 2009, partially offset by increased generation prices resulting from the CBP auction, effective June 1, 2009.
Changes in retail generation KWH sales and revenues in the first six months of 2010, compared to the same period of 2009, are summarized in the following tables:
Retail Generation KWH SalesDecrease
Residential(48.6)%
Commercial(72.3)%
Industrial(60.8)%
Decrease in Retail Generation Sales
(60.5)%
     
Retail Generation Revenues Decrease 
  (In millions) 
Residential $(44)
Commercial  (72)
Industrial  (87)
    
Decrease in Retail Generation Revenues
 $(203)
    
Distribution revenues decreased $26 million in the first six months of 2010, compared to the same period of 2009, primarily due to lower unit prices in all customer classes, partially offset by increased KWH deliveries to industrial customers. Lower unit prices are primarily due to lower transmission rates. Increased industrial deliveries were the result of improving economic conditions, reflecting an increase in KWH deliveries to major automotive customers (36%) and steel customers (37%).

110


Changes in distribution KWH deliveries and revenues in the first six months of 2010, compared to the same period of 2009, are summarized in the following tables:
Increase
Distribution KWH Deliveries(Decrease)
Residential(0.4)%
Commercial(1.6)%
Industrial14.8%
Net Increase in Distribution Deliveries
6.2%
     
Distribution Revenues Decrease 
  (In millions) 
Residential $(5)
Commercial  (6)
Industrial  (15)
    
Decrease in Distribution Revenues
 $(26)
    
Wholesale revenues increased $7 million in the first six months of 2010, compared to the same period of 2009, primarily due to higher revenues from sales to NGC from TE’s leasehold interest in Beaver Valley Unit 2.
Expenses
Total expenses decreased $241 million in the first six months of 2010, compared to the same period of 2009. The following table presents changes from the prior period by expense category:
     
Expenses — Changes Decrease 
  (In millions) 
Purchased power costs $(179)
Other operating costs  (29)
Amortization of regulatory assets, net  (32)
General taxes  (1)
    
Decrease in Expenses
 $(241)
    
Purchased power costs decreased $179 million in the first six months of 2010, compared to the same period of 2009 due to lower volume as a result of decreased KWH sales requirements. Other operating costs decreased $29 million primarily due to reduced transmission expense (assumed by third party suppliers beginning June 1, 2009), lower costs associated with regulatory obligations for economic development and energy efficiency programs and decreased labor expenses. The $32 million decrease in net regulatory asset amortization was primarily due to PUCO-approved cost deferrals and lower MISO transmission cost amortization, partially offset by the absence of MISO transmission and fuel cost deferrals in the first six months of 2010, compared to the same period of 2009.
Other Expense
Other expense increased $13 million in the first six months of 2010, compared to the same period of 2009, primarily due to higher interest expense associated with the April 2009 issuance of $300 million senior secured notes and lower investment income.

111


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 procures generation services for 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’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Net income increased by $13 million in the first six months of 2010, compared to the same period of 2009. The increase was primarily due to lower purchased power costs and decreased amortization of regulatory assets, partially offset by lower revenues and increased other operating costs.
Revenues
In the first six months of 2010, revenues decreased $57 million, or 4%, compared to the same period of 2009. The decrease in revenues is primarily due to a decrease in retail and wholesale generation revenues, partially offset by higher distribution and transmission revenues.
Retail generation revenues decreased $73 million due to lower retail generation KWH sales in commercial and industrial classes, partially offset by higher KWH sales in the residential class. Lower sales to the commercial and industrial classes were primarily due to an increase in the number of shopping customers. Higher KWH sales to the residential class reflected increased weather-related usage resulting from a 105% increase in cooling degree days.
Changes in retail generation KWH sales and revenues in the first six months of 2010, compared to the same period of 2009, are summarized in the following tables:
  Increase 
Retail Generation KWH Sales (Decrease) 
     
Residential  (2.75.1)%
Commercial  4.8(31.0)%
Industrial  (14.624.7)%
Net Decrease in Retail Generation Sales
  (6.410.1)%

     
  Increase 
Retail Generation Revenues (Decrease) 
  (In millions) 
Residential $30 
Commercial  (95)
Industrial  (8)
    
Net Decrease in Retail Generation Revenues
 $(73)
    
Retail Generation Revenues Increase 
  
(in millions)
 
Residential $30 
Commercial  40 
Industrial  33 
Increase in Generation Revenues $103 


124



Revenues from distribution throughputWholesale generation revenues decreased by $117$7 million in the first ninesix months of 20092010, compared to the same period of 20082009; less power was available for sale due to the termination of a decreaseNUG power purchase contract in July 2009.
Distribution revenues increased $17 million in the first six months of 2010, compared to the same period of 2009, due to higher KWH deliveries in all customer classesclasses. Increased usage from warmer weather and lower averageimproving economic conditions in JCP&L’s service territory was partially offset by a decrease in composite unit prices in the residentialcommercial 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.industrial classes.

112



Changes in distribution KWH deliveries and revenues in the first ninesix months of 20092010 compared to the same period of 20082009, are summarized in the following tables.

tables:
Distribution KWH DeliveriesSales DecreaseIncrease 
     
Residential  (4.05.1)%
Commercial  (4.71.7)%
Industrial  (18.61.1)%
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
Increase in Distribution Deliveries
  2.43.1%
Commercial30.0 %
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 DeliveriesDecrease
    
Residential(5.2)%
Commercial(10.2)%
Industrial(12.9)%
    Decrease in Distribution Deliveries(10.3)%

     
  Increase 
Distribution Revenues (Decrease) 
  (In millions) 
Residential $18 
Commercial   
Industrial  (1)
    
Net Increase in Distribution Revenues
 $17 
    
Distribution Revenues Decrease 
  (In millions) 
Residential $(31)
Commercial  (61)
Industrial  (38)
   Decrease in Distribution Revenues $(130)

Expenses

Total expensesTransmission revenues increased $80$4 million in the first ninesix months of 2009 from2010, compared to the same period of 2008.2009, due to an increase in network transmission system revenues from PJM.
Expenses
Total expenses decreased $77 million in the first six months of 2010, compared to the same period of 2009. 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 SalesDecrease
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 DeliveriesDecrease
Residential(5.3)%
Commercial(3.9)%
Industrial(13.1)%
 Decrease in Distribution Deliveries(5.6)%

Distribution RevenuesDecrease
(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)
 
    
 Increase 
Expenses — Changes (Decrease) 
 (In millions)  (In millions) 
Purchased power costs $(338) $(81)
Other operating costs  7  14 
Provision for depreciation  7  5 
Amortization of regulatory assets  (18)
Amortization of regulatory assets, net  (16)
General taxes  (4) 1 
Net decrease in expenses $(346)
   
Net Decrease in Expenses
 $(77)
   
Purchased power costs decreased in the first ninesix months of 20092010 primarily due to the lower KWH sales requirements discussed above and lower unit prices due to reduced energy rates.the termination of a NUG contract in July 2009. Other operating costs increased in the first ninesix months of 20092010 primarily due to higher expenses related to employee benefits and customer assistance programs.tree trimming costs resulting from major storm clean up in JCP&L’s service territory, offset by a favorable labor settlement of $7 million in the second quarter of 2010. Depreciation expense increased due to an increase in depreciable property since the thirdsecond quarter of 2008. Amortization of2009. Net regulatory assetsasset amortization decreased in the first ninesix months of 20092010 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 Divisiondeferral of the Superior Court of New Jersey. On July 10, 2009, the Court upheld the NJBPU’s order and the sale of the plant.storm costs.

113









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 providesprocures generation service tofor those customers electing to retain Met-Ed as their power supplier. On November 3, 2009, FES, Met-Ed Penelec and Waverly restated theirhas a partial requirements wholesale power purchasesales 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 requireswith FES, to supply essentiallynearly all of Met-Ed, Penelec, and Waverly’sits 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 offixed prices through 2010.

For additional information with respect to Met-Ed, please see the information contained in FirstEnergy's ManagementFirstEnergy’s Management’s 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, Market Risk Information, Credit Risk, Outlook and Outlook.New Accounting Standards and Interpretations.

Results of Operations

Net income decreased to $37increased by $3 million in the first ninesix 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 20092010, compared to the same period of 20082009. The increase was primarily due to increased revenues, partially offset by increased purchased power, other operating expenses and amortization of net regulatory assets.
Revenues
The revenue increase of $109 million, or 13%, in the first six months of 2010 compared to the same period of 2009 reflected higher distribution, throughputwholesale and generation revenues, partially offset by a decrease in retail generation and wholesaletransmission revenues. Wholesale
Distribution revenues decreased by $7increased $57 million in the first ninesix 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 20092010, 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. Decreased2009 and 2010, partially offset by lower CTC rates for the residential class. Higher KWH deliveries to commercial and industrial customers reflectedwere due to improving economic conditions in Met-Ed’s service territory. Higher residential KWH deliveries reflect increased weather-related usage due to a 97% increase in cooling degree days in the weakened economy, while decreased deliveries to residential customers werefirst six months of 2010, partially offset by a result of10% decrease in heating degree days for the weather conditions described above.

same time period.
Changes in distribution KWH deliveries and revenues in the first ninesix months of 20092010, compared to the same period of 20082009 are summarized in the following tables:

Distribution KWH Deliveries (Decrease)Increase 
     
Residential  (2.00.7)%
Commercial  (4.74.2)%
Industrial  (11.94.5)%
 Decrease in Distribution Deliveries  (5.6
Increase in Distribution Deliveries
)2.8%

     
Distribution Revenues Increase 
  (In millions) 
Residential $23 
Commercial  21 
Industrial  13 
    
Increase in Distribution Revenues
 $57 
    
Wholesale revenues increased $40 million in the first six months of 2010 compared to the same period of 2009, primarily reflecting higher PJM capacity prices.
Retail generation revenues increased $21 million in the first six months of 2010, compared to the same period of 2009, due to higher composite unit prices in the residential and commercial customer classes and higher KWH sales to all customer classes.

114


Changes in retail generation KWH sales and revenues in the first six months of 2010, compared to the same period of 2009, are summarized in the following tables:
Distribution Revenues
Retail Generation KWH Sales Increase 
  (In millions) 
Residential  $320.7%
Commercial  203.7%
Industrial  113.5%
 
Increase in Distribution RevenuesRetail Generation Sales
  $632.4%
 

     
Retail Generation Revenues Increase 
  (In millions) 
Residential $14 
Commercial  5 
Industrial  2 
    
Increase in Retail Generation Revenues
 $21 
    
Transmission service revenues decreased by $22$9 million in the first ninesix months of 20092010 compared to the same period of 2008,2009 primarily due to decreased revenues related to Met-Ed’s Financial Transmission Rights.Rights revenues. 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$103 million in the first ninesix months of 20092010 compared to the same period of 2008.2009. The following table presents changes from the prior year by expense category:

     
  Increase 
Expenses — Changes (Decrease) 
  (In millions) 
Purchased power costs $61 
Other operating costs  35 
Provision for depreciation  1 
Amortization of regulatory assets, net  8 
General taxes  (2)
    
Net Increase in Expenses
 $103 
    
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 

Purchased power costs increased $61 million in the first six months of 2010 due to an increase in unit costs and increased KWH purchased to source increased generation sales requirements. Other operating costs increased $35 million in the first six months of 2010 compared to the same period in 2009 primarily due to higher transmission congestion expenses. The net amortization of regulatory assets increased by $184$8 million in the first ninesix months of 2009 compared to the same period of 20082010 primarily due to increased transmission cost recovery reflecting lower PJM transmission service expenses and the increased transmission revenues described above. Other operating costsrecovery. General taxes decreased $129$2 million in the first nine months of 2009 primarilymostly 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.Pennsylvania tax amnesty settlement. Depreciation expense increased primarily$1 million due to an increase in depreciable property since the third quarterJune of 2008.2009.

115



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
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 providesprocures generation services tofor those customers electing to retain Penelec as their power supplier. On November 3, 2009, FES, Met-Ed, Penelec and Waverly restated theirhas a partial requirements wholesale power purchasesales 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 requireswith FES, to supply essentiallynearly all of Met-Ed, Penelec, and Waverly’sits 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 offixed prices through 2010.

For additional information with respect to Penelec, please see the information contained in FirstEnergy's ManagementFirstEnergy’s Management’s 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, Market Risk Information, Credit Risk, Outlook and Outlook.New Accounting Standards and Interpretations.

Results of Operations

Net income decreased to $49by $3 million in the first ninesix months of 2009,2010, compared to $62 million in the same period of 2008.2009. The decrease was primarily due to lower revenues, partially offset by lowerhigher 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,other operating costs, partially offset by higher wholesale generation revenues. Wholesalerevenues and lower amortization (deferral) of net regulatory assets and general taxes.
Revenues
In the first six months of 2010, revenues increased $1$50 million, in the first nine months of 2009,or 6.9%, compared to the same period of 2008, primarily reflecting higher KWH sales.

In the first nine months of 2009, retail generation revenues decreased $31 million2009. The increase in revenue was primarily due to higher retail and wholesale generation revenues, partially offset by lower distribution and transmission revenues.
Retail generation revenues increased $39 million in the first six months of 2010, compared to the same period of 2009, primarily due to higher unit prices and KWH sales in all customer classes. Higher unit prices across all customer classes are primarily due to an increase in the generation rate, effective January 1, 2010. Higher KWH sales to the commercial and industrial customer classescustomers were due to weakenedimproving economic conditions; reducedconditions in Penelec’s service territory. Higher KWH sales to the residential customer class werecustomers increased primarily due to decreased weather-related usage, reflecting a 28.5% decrease129% increase in cooling degree days in the first ninesix months of 2009.

2010, partially offset by a 10% decrease in heating degree days for the same time period.
Changes in retail generation sales and revenues in the first ninesix months of 20092010 compared to the same period of 20082009 are summarized in the following tables:

Retail Generation KWH Sales (Decrease)Increase 
    
Residential  (1.4)1.3%
Commercial  (3.2)3.9%
Industrial  (16.2)5.6%
    Decrease in Retail Generation Sales(6.6)%

    
Increase in Retail Generation RevenuesSales
 (Decrease)3.4%
  (In millions)
Residential$(2)
Commercial(6)
Industrial(23)
    Decrease in Retail Generation Revenues$(31) 

     
Retail Generation Revenues Increase 
  (In millions) 
Residential $8 
Commercial  17 
Industrial  14 
    
Increase in Retail Generation Revenues
 $39 
    

132



Revenues from distribution throughput decreased $2Wholesale generation revenues increased $34 million in the first ninesix months of 20092010, compared to the same period of 2008,2009, due primarily to higher PJM capacity prices.
Distribution revenues decreased by $11 million in the first six months of 2010, compared to the same period of 2009, primarily due to decreased deliveries toa decrease in the commercial and industrial sectors reflecting the economic conditionsCTC rate in Penelec's service area. Offsetting this decrease wasall customer classes, partially offset by an increase in the universal service and energy efficiency rates for the residential unit prices due to an increasecustomer class and increased KWH sales in transmission rates, resulting from the annual update of Penelec's TSC rider effective June 1, 2009.all customer classes.

116



Changes in distribution KWH deliveries and revenues in the first ninesix months of 20092010, compared to the same period of 20082009, are summarized in the following tables:

Distribution KWH Deliveries (Decrease)Increase 
    
Residential  (1.4)1.3%
Commercial  (3.2)4.0%
Industrial  (15.4)5.3%
 Decrease in Distribution Deliveries  (6.6)
Increase in Distribution Deliveries
3.5%

    
 Increase 
Distribution Revenues 
Increase
(Decrease)
  (Decrease) 
 (In millions)  (In millions) 
Residential $4  $6 
Commercial  (2)  (10)
Industrial  (4)  (7)
Net Decrease in Distribution Revenues $(2)
   
Net decrease in Distribution Revenues
 $(11)
   
Transmission revenues decreased by $34$8 million in the first ninesix months of 20092010, compared to the same period of 2008,2009, primarily due to lower revenues related to Penelec’s Financial Transmission Rights.Rights revenue. 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 decreasedincreased by $27$45 million in the first ninesix months of 20092010, as compared with the same period of 2008.2009. The following table presents changes from the prior yearperiod by expense category:

Expenses - Changes 
Increase
(Decrease)
 
    
 Increase 
Expenses — Changes (Decrease) 
 (In millions)  (In millions) 
Purchased power costs $(11) $79 
Other operating costs  (5) 16 
Provision for depreciation  5  1 
Amortization of regulatory assets, net  (11)
Amortization (deferral) of regulatory assets, net  (47)
General taxes  (5)  (4)
Net Decrease in Expenses $(27)
   
Net Increase in Expenses
 $45 
   
Purchased power costs decreased by $11increased $79 million or 1.7%, in the first ninesix months of 20092010, compared to the same period of 20082009, primarily due to reduced volume as a result of lower KWH sales requirements, partially offset by increased compositehigher unit prices.costs. Other operating costs decreased by $5increased $16 million in the first ninesix months of 20092010, primarily due to increased locational marginal prices partially offset by lower transmission expenses. The amortization (deferral) of net regulatory assets decreased $47 million in the first six months of 2010, primarily due to reduced labor andincreased cost deferrals resulting from higher transmission expenses and decreased amortization of regulatory assets resulting from lower CTC revenues. General taxes decreased $4 million primarily due to a decrease in contingency reserves basedfavorable ruling on a favorable legal ruling, partially offset by higher pension and OPEB expenses. Depreciationproperty tax appeal in the first quarter of 2010.
Other Expense
In the first six months of 2010, other expense increased $8 million 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$500 million repayment of unsecured notesdebt issuance in AprilSeptember 2009.

117







133


ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4. CONTROLS AND PROCEDURES

(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES – FIRSTENERGY

FirstEnergy'sFirstEnergy’s management, with the participation of its chief executive officer and chief financial officer have reviewed and evaluated the effectiveness of the registrant'sregistrant’s disclosure controls and procedures, as defined in the Securities Exchange Act of 1934, as amended, Rules 13a-15(e) and 15(d)-15(e), 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 officersthe chief executive officer and chief financial officer have concluded that the registrant'sregistrant’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 SeptemberJune 30, 2009,2010, there were no changes in FirstEnergy'sFirstEnergy’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrant'sregistrant’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'sregistrant’s management, with the participation of its chief executive officer and chief financial officer, have reviewed and evaluated the effectiveness of such registrant'sregistrant’s disclosure controls and procedures, as defined in the Securities Exchange Act of 1934, as amended, Rules 13a-15(e) and 15(d)-15(e), 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 officerseach registrant’s chief executive officer and chief financial officer have concluded that such registrant'sregistrant’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 SeptemberJune 30, 2009,2010, there were no changes in the registrants'registrants’ internal control over financial reporting that havehas materially affected, or are reasonably likely to materially affect, the registrants'registrants’ internal control over financial reporting.

118




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 98 and 109 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 1A. RISK FACTORS

FirstEnergy'sFirstEnergy’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, includeincludes a detailed discussion of its risk factors. For the quarter ended September 30, 2009, thereThere have been no material changes to these risk factors.factors for the quarter ended June 30, 2010.

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 thirdsecond quarter of 2009.2010.

                 
  Period 
  April  May  June  Second Quarter 
                 
Total Number of Shares Purchased(a)
  75,577   41,674   549,279   666,530 
                 
Average Price Paid per Share $38.14  $36.28  $34.77  $35.24 
                 
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            
  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'sFirstEnergy’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
None

119



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
   
FirstEnergy
 2.1Amendment No.1 to the Agreement and Plan of Merger, dated as of February 10,
 2010, by and among FirstEnergy Corp., Element Merger Sub, Inc. and Allegheny
Energy, Inc. (incorporated by reference to FirstEnergy’s Form S-4 filed June
4, 2010, Exhibit 2.2, File No. 333-165640)
12Fixed charge ratios
 15Letter from independent registered public accounting firm
 31.1Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 31.2Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 32Certification of chief executive officer and chief financial officer, pursuant
to 18 U.S.C. Section 1350
 101*101*The following materials from the Quarterly Report on Form 10-Q of FirstEnergy
Corp. for the period ended SeptemberJune 30, 2009,2010, 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.
Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The
Registrant will furnish the omitted schedules to the Securities and Exchange
Commission upon request by the Commission.
FES
 
 3.1Amended 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)
4.1Indenture, 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)
4.2First 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)
4.3Form 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)
4.4Form 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)
4.5Form 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)
10.1Registration 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
 12Fixed charge ratios
 15Letter from independent registered public accounting firm
 31.1Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 31.2Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 32Certification of chief executive officer and chief financial officer, pursuant
to 18 U.S.C. Section 1350
OE
 
 12Fixed charge ratios
 15Letter from independent registered public accounting firm
 31.1Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 31.2Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 32Certification of chief executive officer and chief financial officer, pursuant
to 18 U.S.C. Section 1350
CEI
 
 4.1Ninetieth 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)
4.2Form 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)
 12Fixed charge ratios
 15Letter from independent registered public accounting firm
 31.1Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 31.2Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 32Certification of chief executive officer and chief financial officer, pursuant
to 18 U.S.C. Section 1350

136



TE
 
 12Fixed charge ratios
 15Letter from independent registered public accounting firm
 31.1Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 31.2Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 32Certification of chief executive officer and chief financial officer, pursuant
to 18 U.S.C. Section 1350
JCP&L
 
 12Fixed charge ratios
 15Letter from independent registered public accounting firm
 31.1Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 31.2Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 32Certification of chief executive officer and chief financial officer, pursuant
to 18 U.S.C. Section 1350
Met-Ed
 
 10.2The Fourth Restated Partial Requirements Agreement
 12Fixed charge ratios
 15Letter from independent registered public accounting firm
 31.1Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 31.2Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 32Certification of chief executive officer and chief financial officer, pursuant
to 18 U.S.C. Section 1350
Penelec
 
 4.1Company 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)
4.2Form 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)
4.3Form 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)
4.4Supplemental 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)
10.2The Fourth Restated Partial Requirements Agreement
 12Fixed charge ratios
 15Letter from independent registered public accounting firm
 31.1Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
 31.2Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
 32Certification of chief executive officer and chief financial officer, pursuant
to 18 U.S.C. Section 1350

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* 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.

*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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137


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





August 3, 2010
 FIRSTENERGY CORP.
 Registrant
  
 FIRSTENERGY SOLUTIONS CORP.
Registrant
  
 OHIO EDISON COMPANY
 
Registrant
  
 THE CLEVELAND ELECTRIC
 ILLUMINATING COMPANY
Registrant
  
 THE TOLEDO EDISON COMPANY
 RegistrantFIRSTENERGY SOLUTIONS CORP.
  
 METROPOLITAN EDISON COMPANY
 Registrant
  
 PENNSYLVANIA ELECTRIC COMPANYRegistrant
 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
  
  
  
 
Registrant
/s/ Kevin R. Burgess
 Kevin R. Burgess
 Controller
 Controller
(Principal Accounting Officer)

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138